“aging of installations at lng...

22nd World Gas Conference June 1–5, 2003 Tokyo, Japan

Report of Study Group3.3

“Aging of Installations at LNG Terminals”

Rapport du Groupe d’étude 3.3

“Vieillissement des Installations aux Terminaux de GNL”

Chairman/Président

Takehiko Hasegawa

Japan

TABLE OF CONTENTS

1. Abstract 2. Introduction 3. Questionnaire

3.1 Schematic flow chart for LNG receiving terminal 3.2 Contents of questionnaire 3.3 Addressees for questionnaires

4. Information Concerning Replacement of Main Facilities 5. Unloading Arm

5.1 Type 5.2 Outer-diameter 5.3 Number of arms by date of installation 5.4 Operating hours 5.5 Manufacturer 5.6 Information concerning maintenance 5.7 Replacement 5.8 Repair work 5.9 Summary

6. Vaporizer 6.1 Type 6.2 Capacity 6.3 Number of units by date of installation 6.4 Operating hours 6.5 Manufacturer 6.6 Information concerning maintenance 6.7 Replacement 6.8 Repair work 6.9 Summary

7. LNG Pump 7.1 Capacity 7.2 Number of units by date of installation 7.3 Operating hours 7.4 Manufacturers 7.5 Information concerning maintenance 7.6 Replacement 7.7 Repair work 7.8 Summary

8. BOG Compressor 8.1 Capacity 8.2 Number of units by date of installation 8.3 Operating hours 8.4 Manufacturer 8.5 Information concerning maintenance 8.6 Replacement 8.7 Repair work 8.8 Summary

9. Examples of Corrective Measures to Deal With Aging 9.1 Corrective measures to deal with aging of concrete structures 9.2 Corrective measures to prevent corrosion of LNG cryogenic valves 9.3 Deterioration diagnosis at the portion of carbon steel piping contacting a piping

frame 9.4 Deterioration diagnosis of high-density urethane support in LNG piping

10. Study Group 3.3 Membership Appendix 1. Results of the Questionnaire Sent to LNG Receiving Terminals Appendix 2. Results of the Questionnaire Sent to LNG Liquefaction Terminals

1. ABSTRUCT Among LNG liquefaction and receiving terminals, quite a number have been operated for ten or more years since their installation, and some of the facilities in these terminals have revealed problems of so-called aging. To avoid major repair and replacement work in the future and to minimize life-cycle costs of terminal facilities by taking proper steps now, in advance, we started the investigation on the LNG terminal facilities. In this investigation, we have researched all over the world to establish current deterioration states, maintenance states and repair/replacement states of main facilities in LNG receiving/liquefaction terminals built in 1990 or earlier by sending out questionnaires. In general, we can say from the results of this questionnaire-based research that these main LNG facilities show no remarkable phenomena of time-related deterioration, and that any deterioration found so far could be dealt with by properly-conducted daily maintenance.

1.RESUME Parmi les terminaux de liquéfaction et d’arrivée de GNL, un assez grand nombre ont été exploité pendant une période de dix ans ou plus depuis leur établissement, et certaines installations dans ces terminaux ont révélé des problèmes dits de vieillissement. Afin d’éviter des travaux de réparation et de remplacement majeurs dans l’avenir et de minimiser le coût global du cycle de vie des installations de terminal en prenant maintenant des mesures appropriées en avance, nous avons commencé l’investigation sur les installations de terminal à GNL. Dans cette investigation, nous avons recherché dans le monde entier pour vérifier les états actuels de détérioration, les états d’entretien et les états de réparation/remplacement des installations principales dans les terminaux d’arrivée/réception de GNL construits en 1990 ou avant en envoyant des questionnaires. En règle générale, nous pouvons déduire des résultats de cette recherche basée sur les questionnaires que ces installations principales à GNL ne montrent aucun phénomène remarquable de détérioration due au vieillissement, et que toute détérioration éventuellement décelée peut être réglée en exécutant un entretien journalier approprié.

2. Introduction LNG liquefaction terminals have gradually grown in number since the first one to be operated on a commercial basis was established at Arzew in Algeria in 1964. At present, 15 terminals all over the world are exporting approximately 100 million tons of LNG. On the other hand, terminals receiving LNG have also gradually grown in number since the first shipment was received at Cambay Island in England in 1959, the current number being 40 including those in Europe, United States, and the Far East, in particular Japan. Among these terminals, quite a number have been operated for ten or more years since their installation, and some of the facilities in these terminals have revealed problems of so-called aging. For these facilities, it is possible to avoid major repair and replacement work in the future and to minimize life-cycle costs of terminal facilities by taking proper steps now, in advance. To facilitate this work, we started this investigation, under the above-mentioned circumstances, in order to clarify such questions as what kinds of maintenance are being carried out at main facilities in LNG terminals at present, at what points attention should be given toward such maintenance, and what particular corrective measures could be implemented to deal with aging. In this investigation, we have researched all over the world to establish current deterioration states, maintenance states and repair/replacement states of main facilities in LNG receiving/liquefaction terminals built in 1990 or earlier (those terminals that had been operated for 10 years since the installation at the beginning of this work), by sending out questionnaires asking about deterioration of sections or parts, methods of maintenance and whether repair/replacement has been made or not, etc. In general, we can say from the results of this questionnaire-based research that these main LNG facilities show no remarkable phenomena of time-related deterioration, and that any deterioration found so far could be dealt with by properly-conducted daily maintenance. In addition, it became clear in the course of this investigation that the points/sections that require special attention in planning corrective measures to deal with aging in LNG terminals include piping supports, concrete structures, materials for insulation, etc. In this report, we provide detailed results of this investigation and introduce a few examples of particular corrective measures to deal with aging, as obtained during the investigation. We will report on receiving terminals only, because although the research into liquefaction terminals was conducted in the same way, the number of replies to that questionnaire was not sufficient to carry out proper analysis.

3. Questionnaire 3.1 Schematic flow chart for LNG receiving terminal 3.2 Contents of questionnaire

This questionnaire is divided into two parts (Questions A and B).

[Question A]

With regard to target facilities (LNG tank, cryogenic piping, insulation of cryogenic piping, sea water pump, steam boiler and control system), we asked:

- Whether any replacement has been made or not. - If replacement has been made, reason for this.

[Question B]

With regard to target facilities (LNG unloading arm, LNG vaporizer, LNG pump, BOG compressor), we asked :

- Information concerning facilities: capacity, year of installation, manufacturer, etc. - Information concerning maintenance: With regard to sections or parts that are expected

to suffer from time-related deterioration, material, maintenance method, deterioration mode and its diagnosis method, and preventive maintenance being conducted.

- State of replacement: Where any replacement has been made, the section or part that triggered the replacement, deterioration mode and years of operation before replacement

- State of repair work: Repaired section or part, deterioration mode, repairing method (corrective measure), years of operation before deterioration

- Particular corrective measures being conducted to deal with aging

In the questionnaire sent to liquefaction terminals, the same questions as for receiving terminals were asked, while the target facilities for question A consisted of acid gas remover, dehydrator, main heat exchanger, refrigerating equipment and control system, and target facilities

BOG compressor

LNG tank

Return gas blower

LNG pumpCryogenic piping

Gas return arm

Gas piping

Sea water pump

Steam boiler

LNG unloading arm

LNG vaporizer

Control system

Insulation of cryogenic piping

for question B consisted of LNG loading arm and gas return arm, sea water pump, steam boiler and cycle compressor and driver. 3.3 Addressees for questionnaires

The questionnaire was sent to those terminals that were built in 1990 or earlier. Out of

28 receiving terminals to which the questionnaire was sent, 26 replied (rate of reply 93%). Out of 11 liquefaction terminals approached, 5 replied (rate of reply 45%). Regarding liquefaction terminals, we provide the results only because the number of replies was too small to conduct analysis.

4. Information concerning replacement of main facilities

No LNG tank has been replaced so far. Similarly, cryogenic piping, seawater pumps, and steam boilers have rarely been replaced.

As for insulation material, while 11 terminals conducted replacement, its deterioration

begins to become evident from about 15 years after installation, judging from the fact that no replacement has been made in any terminals that began operation in 1989 or later. The Main reasons for replacement are the deterioration in insulation performance because of water penetration and the corrosion of cover metal. On replacement, 3 terminals used the same type of material again, while 10 terminals implemented some changes regarding materials for insulation and coversheet metal, insulation structure, etc.

The replacement of the control system has been implemented at 100% of terminals that

have operated for 20 years after installation, while including terminals that have operated for 15 years after installation, the replacement rate is 84%. In addition, one terminal that began operation in 1989 also carried out its replacement. These control systems have been replaced for reasons other than time-related deterioration (termination of manufacturer’s maintenance, etc.).

5. Unloading arm Analysis was conducted on the data obtained from 137 unloading arms in total.

5.1 Type

LNG unloading arms and gas return arms occupy 76% and 24% respectively, figures that

agree well with their general installation ratio of 3 to 1. 5.2 Outer-diameter

Almost all unloading arms (84%) are of 400mm, 16% being 300mm or less.

5.3 Number of arms by date of installation

Twenty-one percent of unloading arms were installed in the 1970s, 44% in the 1980s,

23% in the 1990s and 9% in the 2000s. The number of installed arms appears to have increased along with the construction of

LNG terminals in the 1970s, due to both the construction of LNG terminals and the expansion of existing terminals in the 1980s, and along with the expansion of terminals in the 1990s.

The increase in number of installed unloading arms due to expansion is smaller than

those of vaporizers and LNG pumps, partly because a complete set of unloading arms has to be installed when building a terminal, and partly because, unlike vaporizers and LNG pumps, the number of installed unloading arms will not simply increase in proportion to the growth of terminal capacity. 5.4 Operating hours

Among 86 unloading arms for which responses on operating period were given in hours,

58% (50 arms), on the basis of number of arms, have been operated for less than 10,000 hours and 20% (17 arms) for 10,000 or more to less than 20,000 hours, because their operating hours are counted only at receiving. 5.5 Manufacturer

Unloading arms were made by Niigata Engineering, FMC, SVT, Luceat, Wiese and

Schwelm.

5.6 Information concerning maintenance (1) Pipe (a) Material

On the basis of number of terminals, 96% are of stainless steel, and 8% (2 terminals) of aluminum (materials overlap), while on the basis of number of arms, 96% are of stainless steel, and 4% (6 arms) of aluminum. The aluminum pipes were installed in 1997, 1971. All pipes installed in 1972 or later are made of stainless steel except for those installed during replacements by using aluminum materials due to various limitations. (b) Methods and contents of maintenance

Although almost all the terminals have adopted Time Based Maintenance, 3 terminals are using Condition Based Maintenance. Painting, cleaning and parts exchange are the main contents of the maintenance.

Measurements of ferrite volume, etc. are included in the Condition Based Maintenance.

(c) Deterioration mode and diagnosis method

Because of the material, installation environment and operating conditions, the main deterioration modes assumed are corrosion and deformation, while abrasion (wear out), etc. are also assumed. Visual inspection is most frequently used as the diagnosis method, while other methods such as liquid penetration test, leak test, dimension check, etc. are also used. (2) Joint (a) Material

On the basis of the number of terminals, 96% are of stainless steel, 8% of aluminum

Joint

Joint

PipePipe

(materials overlap) (b) Methods and contents of maintenance

Although almost all the terminals have adopted Time Based Maintenance, 4 terminals are using Condition Based Maintenance. Cleaning and parts exchange are the main contents of maintenance.


While, due to structural reasons, abrasion (wear out) and deformation are assumed to be the deterioration mode in almost all cases, corrosion, etc. are also assumed. Leak test and visual inspection are most frequently used as the diagnosis method, while liquid penetration test and dimension check are also used. 5.7 Replacement

On the basis of the number of arms, 22 arms were replaced (16%).

(1) Reason

Of the 137 arms covered, 7 arms were replaced for deformation, 3 arms were replaced for corrosion, 19 arms for other reasons (reasons overlap).

Of those arms replaced for other reasons, 10 arms were replaced along with the

installation of ERS (Emergency Release System), and 5 arms were replaced for the crash of ship against the pier.

Almost all unloading arms, therefore, have yet been replaced for aging.

(2) Deteriorated (replaced) section or part

This category corresponds to the reasons of replacement. The sections or parts that cause the replacement of the 22 arms are 12 pipes, 5 Joints

and 15 others (deteriorated (replaced) sections or parts overlap). (3) Years of operation before replacement

On the basis of the number of arms, unloading arms have been replaced in a relatively short interval, 86% within 14 to 20 years and 14% in more than 20 years. This could be explained by the fact that the replacement was carried out mainly due to the crash of ship, ERS installation, etc., not due to aging. (4) Method for replacement

All replacements have been implemented with design changes. Factors that seem to contribute to this are that one of the reasons for replacement was ERS installation and that, when a certain number of years had passed since the installation, the manufacturer’s standard parts may have been changed in design. 5.8 Repair work (1) Repaired section or part

Joints occupy 49% on the basis of number of arms. This appears to be due to the fact that joints are a consumable part and require periodical replacement. Other repaired sections or parts (51%) include flexible hoses, cables, etc. (2) Deterioration mode

On the basis of number of arms, 42% were due to abrasion (wear out), 18% to deformation, and 5% to corrosion. Factors that seem to contribute to this are that the main deterioration mode of joints is abrasion (wear out). (3) Repairing method

On the basis of number of arms, 65% were replaced with a new one of the same design. This could be explained by the fact that the main form of repair is to replace joints, which are a consumable part and would be replaced with a new one of the same design method. (4) Years of operation before deterioration

On the basis of number of arms, less than 10 years occupies 63%. This appears to be due to the fact that the manufactures, which occupy the majority share at present, recommend a maintenance cycle of less than 10 years. 5.9 Summary

Almost all unloading arms have not been replaced due to aging. This is explained by the

fact that almost all the time-related deterioration cases consist of abrasion (wear out) of joints that are a consumable part requiring periodical replacement and corrosion of external parts like flexible hoses, etc. Thus, based on the information gathered so far, long term integrity of the facilities could be sustained by regularly replacing the parts of joints and replacing external parts like flexible hoses, etc. after a certain period.

6. Vaporizer

Analysis has been conducted based on the data obtained from 277 units of vaporizer in total. 6.1 Type

About 2/3 (63%) are ORV (Open Rack Vaporizer), 29% are SCV (Submerged

Combustion Vaporizer), and 8% are Shell and Tube. This appears to be due to the fact that the ORV type, with a simple structure and relatively low running cost is preferred as the base load vaporizer.

ORVs are utilized at 18 terminals, SCVs at 15, and Shell and Tubes at 5. Five terminals are equipped with ORV only, 9 terminals with ORV and SCV, 3 with ORV

and Shell and Tube, 1 with SCV and Shell and Tube, 5 with SCV only, and 1 with ORV, SCV and Shell and Tube. All terminals equipped with ORV only are located in Japan for electric power generation, while all terminals with SCV only are located in Europe and the United States. 6.2 Capacity

On the basis of number of units, those of less than 50 t/h occupy 10%, 50 t/h or more to

less than 100 t/h 32%, 100 t/h to 150 t/h 38%, 150 t/h to 200 t/h 18%, 250 t/h or more occupy 2%, and the largest one has a capacity of 297 t/h. 6.3 Number of units by date of installation

On a number of units basis, 2% were installed in the 1960s, 22% in the 1970s, 38% in the

1980s, 32% in the 1990s, and 6% in the 2000s. The number of installed vaporizers appears to have increased along with the construction

of LNG terminals in the 1970s, due to both the construction of LNG terminals and the expansion of existing terminals in the 1980s, and along with the expansion of terminals in the 1990s.

A considerable number of vaporizers had been installed even in the 1990s, because the

number of installed vaporizers, like LNG pumps, tends to increase in proportion to the growth of the terminal capacity. 6.4 Operating hours

Among 268 units of vaporizer for which the operating hours were given, 52% (141 units)

have been operated for less than 50,000 hours, 26% (70 units) for 50,000 or more to less than 100,000 hours, 15% (40 units) for 100,000 to 150,000 hours, 6% (15 units) for 150,000 to 200,000 hours, and 1% (2 units) for 200,000 or more hours.

Many units have been operated for a relatively short period of time. Factors that seem to

contribute to this are that many units have been installed in recent years, and that some SCVs are installed as spare units.

6.5 Manufacturer

Vaporizers were manufactured by Sumitomo Precision Products, Kobe Steel, John

Thurley, Kaldair, T-Thermal, Air Liquide, Deal, A.C.B, Mitsubishi Kakoki Kaisha, Hitachi, Nittetsu Chemical Engineering, Ryan, Manning & Lewis, Ceico, Chicago Power and Process and Kimura Chemical Plants.

6.6 Information concerning maintenance

Open Rack Vaporizer

Submerged Combustion Vaporizer

Tube

Header

Tube

Blower

Burner

Water bath

Shell and Tube Type Vaporizer (1) Tube and Header (ORV) (a) Material

Both tubes and headers are all made of aluminum.

(b) Methods and contents of maintenance On the basis of number of terminals, for both tubes and headers, approximately 75% are

covered by Time Based Maintenance, while Condition Based Maintenance and Break Down Maintenance are also adopted. Repair of aluminum zinc alloy coating and cleaning are the main contents of maintenance.


For both tubes and headers, the main deterioration modes assumed are corrosion and abrasion (wear out), and their diagnosis is principally conducted by means of visual inspection, tube thickness inspection (including measurement of film thickness of aluminum zinc alloy coating), and leak test. (2) Tube (SCV) (a) Material

All tubes are made of stainless steel.

(b) Method and contents of maintenance On the basis of number of terminals, approximately 70% are preserved by Time Based

Maintenance, while Condition Based Maintenance and Break Down Maintenance are also adopted. Corrosion prevention, and cleaning are the main contents of maintenance.

Tube

Shell

Sea

NG

LNG


The main deterioration modes assumed are corrosion and abrasion (wear out), and their diagnosis is principally conducted by means of visual inspection, shell and tube thickness inspection, and leak test. (3) Shell and Tube (Shell and Tube type) (a) Material

On the basis of number of terminals, 100% of the tubes are made of stainless steel, 60% of the tubes others (brass), and 40% of the tubes titanium (materials overlap). All the shells are made of stainless steel. Material change has been carried out to improve both their corrosion resistance and heat-exchanging performance.

(b) Method and contents of maintenance

On the basis of number of terminals, for both shells and tubes, approximately 80% are maintained by Time Based Maintenance, while Condition Based Maintenance and Break Down Maintenance are also adopted. Cleaning and painting are the main contents of maintenance.


For both shells and tubes, the main deterioration mode assumed is corrosion. The diagnosis is, for both shells and tubes, conducted by means of visual inspection and shell and tube thickness inspection, while shells are principally diagnosed by leak test. (4) Burner (SCV) (a) Material

The majority (78%) of burners are made of stainless steel, while 22% are made of carbon steel.


On the basis of number of terminals, approximately 80% are maintained by Time Based Maintenance, while Condition Based Maintenance is also adopted. Cleaning and parts exchange are the main contents of maintenance.


The main deterioration modes assumed are corrosion, crack and excessive external stress, and their diagnosis is principally conducted by means of visual inspection. (5) Water bath (SCV) (a) Material

Almost all (88%) of the water baths are made of concrete.

(b) Method and contents of maintenance On the basis of number of terminals, water baths are maintained mainly by Time Based

Maintenance and Condition Based Maintenance, while for some of them Break Down Maintenance is adopted. Corrosion prevention, painting and cleaning are the main contents of

maintenance.

(c) Deterioration mode and diagnosis method Cracking of concrete and corrosion of reinforcing steel bars are assumed as main

deterioration modes, which are diagnosed principally by visual inspection. (6) Blower (SCV) (a) Material

Almost all (83%) of the blowers are made of carbon steel. (b) Method and contents of maintenance

On the basis of number of terminals, approximately 90% of blowers are maintained by Time Based Maintenance, while Condition Based Maintenance is also adopted. Parts exchange, painting and cleaning are the main contents of maintenance.


Corrosion and abrasion (wear out) are assumed as main deterioration modes, which are diagnosed principally by visual inspection and performance test.

6.7 Replacement On the basis of number of units, 16% (43 units) out of 277 vaporizer units have been

replaced. They consist of 15 units of ORV (One unit has been replaced twice), 23 units of SCV (One unit has been replaced twice) and 5 units of Shell and Tube type. (1) Reason

Among 43 units (2 vaporizers were replaced twice) for which the reason for replacement was specified, 22% (11 units) were replaced for corrosion, 10% (5 units) for cracking, 6% (3 units) for abrasion (wear out), 8% (4 units) for damage by external stress and 53% (26 units) for other reasons (reasons overlap). It should be noted that the above figures for replacements include the cases (13 units) of blowers, burners, etc. only for SCV. Regarding aging, main reasons for replacement specified are corrosion and cracking. Other main reasons specified, such as capacity building and environmental corrective measures appear to indicate that such replacement had nothing to do with aging.

In the case of ORV, corrosion and cracking are more often referred to, while with regard to

SCV and Shell and Tube, other reasons such as capacity building are more often specified than corrosion and cracking. (2) Deteriorated (replaced) section or part

Tubes (ORV, SCV, Shell and Tube) occupy 28%, blowers 21%, burners 20%, and water baths 8%. Blowers of SCV that are categorized as a rotation machine have also been replaced at a relatively high percentage. (3) Years of operation before replacement

Vaporizers have been replaced at a relatively short interval, as 25% have been replaced in less than 5 years, 6% in 5 or more to less than 10 years, 25% in 10 to 15 years, 11% in 15 to 20 years, and 11% in 20 or more years. This appears to be due to the fact that many of them were replaced for capacity building, environmental corrective measures, etc. (4) Method for replacement

82% of replacements have been implemented with design changes. Factors that seem to contribute to this are that the majority of replacements are for capacity building, environmental corrective measures, etc., and that, when a certain number of years has passed since installation, the manufacturer’s standard parts may have been changed in design in order to forestall factors of time-related deterioration. 6.8 Repair work (1) Repaired section or part

Tubes (ORV, SCV, Shell and Tube) occupy 58%, and headers of ORV occupy 26%. (2) Deterioration mode

Corrosion and abrasion (wear out) occupy 76%. This appears to be due to the fact that almost all the repaired sections or parts consist of the tubes (ORV, SCV, Shell and Tube) and headers of ORV. (3) Repairing method

Repair of aluminum zinc alloy coating, which are sacrificial anodes, is the main repairing method (56%), while welding repair occupies 15%. At a few terminals, however, welding repair is being utilized against cracking. (4) Years of operation before deterioration

Before deterioration, 9% had been operated for less than 5 years, 67% for 5 to 10 years, and 19% for 10 to 15 years. The fact that the repair of aluminum zinc alloy coating is the main repairing method is reflected in these levels of operational periods. 6.9 Summary

In the case of vaporizers, replacement due to time-related deterioration has been

implemented at some terminals mainly for ORV. Factors that seem to contribute to this are that corrosion may occur because many vaporizers utilize sea water as their heat source, and that vaporizer bodies suffer from severe thermal stresses caused by alternating normal and cryogenic temperatures they encounter when started and stopped, both of which lead to deterioration with the passage of time.

Aluminum zinc alloy coating, the sacrificial anode of ORV, is consumables part and

require periodical repair work. The long term integrity of ORV facilities, however, could be sustained by carrying out proper maintenance of aluminum zinc alloy coating and by setting suitable materials, structure, operating conditions, etc. to relieve the thermal stress on the vaporizer body.

7. LNG pump 7.1 Capacity

With regard to the capacity of LNG pumps, 40% operate at less than 100 t/h, and 43%

from 100 or more to less than 200 t/h, thus 83% of the total number operate at less than 200 t/h. The largest LNG pump has a capacity of 310 t/h.

7.2 Number of units by date of installation

The number of installed LNG pumps increased substantially along with the construction of

LNG terminals in the 1970s. The number appears to have increased due to both the construction of LNG terminals and the expansion of existing terminals in the 1980s, and along with the expansion of terminals in the 1990s.

7.3 Operating hours

Among 394 units of LNG pumps for which details of operating hours were given, 139 units

(35%) have been operated for less than 20,000 hours, 76 units (19%) for 20,000 or more to less than 40,000 hours, 104 units (26%) for 40,000 to 60,000 hours, 35 units (9%) for 60,000 to 80,000 hours, and 40 units (10%) for 80,000 or more hours.

7.4 Manufacturer

The manufacturers are J.C.Carter,Shinko,Ebara,Nikkiso,Hitachi,Cryostar,Eaco,

David Brown,Byron-Jackson,Sulzer and Guinard.


Diffuser

Shaft

Bearing

Inducer

Impeler

Balance Disc

Motor

Shaft

Diffuser

(1) Shaft (a) Material

Stainless steel is most frequently used, while other materials such as 9% Ni steel and aluminum alloy are also utilized.

(b) Methods and contents of maintenance

Time Based Maintenance or Condition Based Maintenance has been carried out, the main contents of which consist of cleaning and parts exchange.


Curvature is the most frequently assumed deterioration mode, while abrasion (wear out), cracking, deformation, etc. are also assumed. Almost all the terminals are using size check and visual inspection as their diagnosis method, while one third of the terminals are using liquid penetration test. (2) Impeller (a) Material

Approximately 90% of terminals use aluminum alloy.

(b) Methods and contents of maintenance Time Based Maintenance or Condition Based Maintenance has been carried out, the

main contents of which consist of cleaning and parts exchange.

(c) Deterioration mode and diagnosis method Abrasion (wear out) is the most frequently assumed deterioration mode, while

deformation and cracking are also assumed. Visual inspection has been adopted as the diagnosis method at almost all the terminals, followed in number by size check and liquid penetration test.

(3) Balancing disc (a) Material

Stainless steel is used in 76% of terminals, while other terminals use aluminum, etc.

(b) Methods and contents of maintenance Time Based Maintenance or Condition Based Maintenance has been carried out, the

main contents of which consist of cleaning and parts exchange.

(c) Deterioration mode and diagnosis method Almost all the deterioration modes assumed are abrasion (wear out) and deformation, for

which visual inspection and size check are principally used as the diagnosis method. (4) Bearing (a) Material

Almost all the bearing materials are made of stainless steel.


Time Based Maintenance or Condition Based Maintenance has been carried out, the main content of which is parts exchange.


Although the main deterioration mode assumed is abrasion (wear out), deformation has also been assumed at about half of the terminals. Principal diagnosis methods are visual inspection and size check .

7.6 Replacement (1) Reason for replacement

Out of 643 LNG pumps, only 22 units (3%) have been replaced so far. Among 22 LNG pumps, 18 were replaced due to capacity building or probable design problem. 4 were replaced due to erosion, which took place at the section other than shaft, impeller, balancing disc or bearing.

(2) Years of operation before replacement

Of these 22 units replaced so far, 6 had been operated before replacement for 32 years, 2 for 23 years, 2 for 22 years, 3 for 13 years,7 for 4 years, and 2 for 1 year

(3) Type of replacement

All most all replacements were implemented with design change.

7.7 Repair work (1) Repaired section or part

For LNG pumps, the section or part mainly repaired is its bearing, followed by its shaft and impeller.

(2) Deterioration mode Almost all the repairs are due to abrasion (wear out), which has been dealt with by parts

exchange.

(3) Repairing method Almost all the repairs have been dealt with by parts exchange.

(4) Years of operation before deterioration Parts exchange is likely to be carried out within nearly 5 years.

7.8 Summary

For LNG pumps, almost all the time-related deterioration cases are due to abrasion (wear

out), and the deteriorated sections or parts are exchangeable. The facilities, therefore, could be preserved in a sound condition by periodical parts exchange, parts exchange with monitoring of their condition, etc. Thus, LNG pumps are rarely replaced due to time-related deterioration.

8. BOG compressor

8.1 Capacity 28% of BOG compressors have a capacity of 5,000 m3N/h to 9,999 m3N/h, 32% of them

10,000 m3N/h to 14,999 m3N/h, and 26% of them 14,999 m3N/h to 19,999 m3N/h. The largest is a booster compressor having a capacity of 22,400 m3/h. Most of the smaller compressors having a capacity of less than 5,000 m3N/h had been installed by 1989.

8.2 Number of units by date of installation

The number of installed BOG compressors increased substantially along with the

construction of LNG terminals in the 1970s. The number appears to have increased due to both the construction of LNG terminals and the expansion of existing terminals in the 1980s, and along with the expansion of terminals in the 1990s.

8.3 Operating hours

The operating hours of 18 units (23%) are between 60,000 and 80,000 hours. Those of 17

units (21%) are between 20,000 and 40,000 hours. While there are some BOG compressors that have been operated for more than 100,000 hours, none has been replaced due to time-related deterioration.

8.4 Manufacturer

The manufacturers are Ishikawajima-Harima Heavy Industries,Dresser-Rand,

Burton Corblin,Nuovo Pignone,Kobe Steel,Cooper-Bessemer,Sulzer,Arial and Solar Turbines.


(1) Shaft (a) Material

Carbon steel is used at 79% of terminals, while stainless steel is used at others.

(b) Methods and contents of maintenance Almost all terminals have adopted Time Based Maintenance, while Condition Based

Maintenance has also been carried out at approximately 20% of terminals. The main content is cleaning.


The assumed deterioration modes are deformation, abrasion (wear out), cracking, and curvature. The main diagnosis methods consist of dimension check and visual inspection, while 54% of terminals are using liquid penetration test. (2) Piston (a) Material

Approximately 70% of terminals use aluminum, while stainless steel and carbon steel are used in other terminals.


Almost all terminals have adopted Time Based Maintenance, while Condition Based Maintenance has also been carried out at approximately 20% of terminals. The main contents are cleaning.


Deformation is assumed as the deterioration mode at approximately 70% of terminals, while abrasion (wear out) is assumed at about 50% of terminals. The main diagnosis methods consist of dimension check and visual inspection, while 21% of terminals are using liquid penetration test. (3) Piston ring (a) Material

Resin is used in 75% of the terminals.


Maintenance has also been carried out at approximately 30% of terminals. The maintenance consists of parts exchange because the piston ring is a consumable part.


The characteristic of the part naturally points to abrasion (wear out) as its deterioration mode, while deformation is also assumed at 43% of terminals. As the part is an abrasive member, the main diagnosis methods consist of size inspection and visual inspection. (4) Piston rod

(a) Material

Carbon steel is used at about half of the terminals.




Abrasion (wear out) is assumed as the deterioration mode at 85% of terminals, followed by curvature and deformation. The main diagnosis methods consist of size inspection and visual inspection, while 54% of terminals are using liquid penetration test. (5) Connecting rod (a) Material

Carbon steel is used at approximately 70% of terminals, while other terminals use stainless steel.


Almost all terminals have adopted Time Based Maintenance, while Condition Based Maintenance has also been carried out at approximately 16% of terminals. The main content is cleaning.


Abrasion (wear out) is assumed as the deterioration mode at approximately 70% of terminals, followed by deformation and cracking. Size inspection and visual inspection are used as the diagnosis method at approximately 70% of terminals, while 40% of terminals are using liquid penetration test. (6) Cylinder liner (a) Material

Carbon steel and stainless steel occupy approximately 30% respectively.


Maintenance has also been carried out at approximately 16% of terminals. The main content is cleaning, while half of the terminals are using parts exchange.


As the cylinder liner is a sliding part, abrasion (wear out) is assumed as its main deterioration mode, while deformation and cracking are assumed at half and 30% of the terminals respectively. The main diagnosis methods consist of size inspection and visual inspection.

(7) Snubber tank

(a) Material Because cryogenic BOG is handled in this tank, stainless steel is used in most cases.

(b) Method and contents of maintenance Almost all terminals have adopted Time Based Maintenance, while Condition Based


(c) Deterioration mode and Diagnosis method

Deformation is assumed as the deterioration mode at 60% of terminals, while corrosion is assumed at 50% of terminals. The main diagnosis method is visual inspection, while wall thickness inspection and liquid penetration test are also used. (8) Cylinder support (a) Material

Carbon steel is used at 60% and stainless steel is used at approximately 40% of terminals.


Almost all terminals have adopted Time Based Maintenance, while Condition Based Maintenance has also been carried out at approximately 16% of terminals. While the main content is cleaning, painting is used at 50% of terminals.

(c) Deterioration mode and Diagnosis method

Corrosion and deformation are assumed as the deterioration mode at more than 50% of terminals, followed by cracking. The main diagnosis method is visual inspection, while size inspection and liquid penetration test are also used. 8.6 Replacement

Only one BOG compressor has been replaced with design change after 14 years of

operation, in order to change its capacity, not due to time-related deterioration.

8.7 Repair work (1) Repaired section or part

The sections or parts that have been frequently repaired are sliding parts such as piston rings, cylinder liners, etc

(2) Deterioration mode

The main deterioration mode is abrasion (wear out).

(3) Corrective measure Almost all the repairs have been dealt with by parts exchange. In some cases, this parts

exchange includes material change.

(4) Years of operation before deterioration Parts exchange is likely to be carried out within nearly 5 years.

8.8 Summary

For BOG compressors, almost all the time-related deterioration cases are due to abrasion

(wear out), and the deteriorated sections or parts are exchangeable. The facilities, therefore, could be maintained in a sound condition by periodical parts exchange. This parts exchange can be carried out either periodically or through monitoring of their conditions, etc. Thus, no replacement of BOG compressors has been required due to time-related deterioration.

9. Examples of corrective measures to deal with aging 9.1 Corrective measures to deal with aging of concrete structures

In the concrete structures such as LNG receiving piers, ORVs, etc. that contact with sea

water and are splashed by waves, chloride ions in the sea water penetrate them causing corrosion and expansion of the internal reinforcing bars, resulting in such salt damage to the concrete as cracks, rust water, etc.

For those facilities built in the 1970s, in spite of environmental shutoff measures by

surface coating that have been implemented from the 1980s, salt damages caused by the chloride ions that had already penetrated into the concrete before those measures were implemented have become obvious recently. In the case of facilities built in the 1980s or later, although their durability is relatively high thanks to the measures taken to thicken the “cover” that indicates the concrete thickness from its surface to the main reinforcing bars, some corrosion of reinforcing bars has been recognized in recent years.

Thus, corrective measures have been implemented, according to the degree of

deterioration of the concrete, by introducing new technologies while taking into account the remaining life of the concrete structures, executability at the site, execution costs, etc., and also by considering life cycle costs.

In particular, taking into account the results of research into time-related deterioration, life

cycle costs, etc., corrective measures to deal with salt damage have been implemented by adopting “FRP frame technique” for LNG receiving piers, “Carbon fiber sheet gluing technique,” “Cross section repairing plus surface coating,” and “Surface coating” techniques for ORV frame steel.

9.2 Corrective measures to prevent corrosion of LNG cryogenic valves

For the LNG cryogenic valves installed before the 1970s, measures involving replacing

valves, etc. will be required, because, although the material of the valves at the portion where it contacts with LNG is stainless steel, the remaining portions, i.e., the valve stem seal portion and operating portion are made of carbon steel, so parts failure leading to an LNG leak might occur because of wall thinning due to corrosion during future long term operations.

In the case of lines including the first valve of LNG tank etc. where it is difficult to stop the

line, repairing work has been implemented by developing a “PVR: Purge-less Valve Repair” technique and jigs that allow the repair and maintenance of valves even under a condition in operation.

9.3 Deterioration diagnosis at the portion of carbon steel piping contacting a piping frame

At the portion of carbon steel contacting the piping frame (rack) , where slight movement

is always repeated because of the shrinking and expansion of piping due to the temperature difference between day and night and between seasons, it is difficult to secure the integrity of painting. In addition, the atmosphere at the portion tends to promote corrosion more intensely than at other portions of piping, as its geometry is such that the rainfall is accumulated and its

evaporation is prevented. With regard to the non-destructive inspection method for this portion, the best practice

with adequate precision has not been found, though several methods like “RACK THROUGH” etc. have recently been developed and proposed. As a method that consists of raising piping and verifying its condition is most reliable, available portions have, with considerable efforts and costs, been verified by implementing that method. On the other hand, for those portions where raising the piping is almost impossible, several combinations of existing methods and practices have been examined. As a result, an inspection method utilizing gamma rays is at present established.

9.4 Deterioration diagnosis of high-density urethane support in LNG piping

The high-density urethane blocks used for support of LNG piping have begun to show a

wet condition, some cracks, etc. as they have endured a long period of time. Sampling and property confirmation of the urethane block were carried out so that the timing of its replacement can be determined from its visual conditions by taking into account its performance to support piping and to provide insulation. As a result, criteria for replacement have been established.

The test results indicated that even a urethane block in which cracks have occurred does

possess sufficient compressive strength, provided that the crack is not too long. Thus, regarding urethane blocks with cracks, a criterion for replacement evaluated by the crack length has been established.

On the other hand, thermal conductivity was found to be worsened in all cases. Based

on this result, frosting found on the surface of urethane blocks has been specified as a criterion for their replacement from the viewpoint of its insulation performance.

10. Study Group 3.3 Membership

Mr. Takehiko Hasegawa, Osaka Gas, Japan (Coordinator)

Mr. Seiichi Uchino, Tokyo Gas, Japan (Secretary)

Dr. Anthony Acton, BG International, UK

Mr. Jan Heyse, FLUXYS nv, Belgium

Dr. Seongho Hong, KOGAS, Korea

Dr. Victor Logatski, JSC GASTRANSIT, Ukraine

Mr. Henni Mekki, SONARTRACH, Algeria

Ms. Pascale Morin, Total Fina Elf, France

Mr. Suparman Triseputro, PT Arun NGL, Indonesia

Appendix 1. Results of the Questionnaire Sent to LNG Receiving Terminals

1.REPLACEMENT of MAIN FACILITIES

The reason for the replacement

Replacement of main facilities

0 5 10 15 20 25 30

LNG tank

Cryogenic piping

Insulation ofcryogenic piping

Sea water pump

Steam boiler

Control system

numbers

Yes No

Cryogenic piping

0 1 2 3 4 5

Abrasion

Curvature

Corrosion

Crack

Deformation

Others

numbers

Insulation of cryogenic piping

0 5 10 15 20

Abrasion

Curvature

Corrosion

Crack

Deformation

Others

numbers

Sea water pump

0 1 2 3 4 5

Abrasion

Curvature

Corrosion

Crack

Deformation

Others

numbers

Steam boiler

0 1 2 3 4 5

Abrasion

Curvature

Corrosion

Crack

Deformation

Others

numbersControl system

0 5 10 15 20

Abrasion

Curvature

Corrosion

Crack

Deformation

Others

numbers

The method for the replacement

Cryogenic piping

0 1 2 3 4 5

Replacement with the samedesigned equipment

Material change

Design change

Others

numbersInsulation of cryogenic piping

0 1 2 3 4 5 6


Material change

Design change

Others

numbers

Sea water pump

0 1 2 3 4 5


Material change

Design change

Others

numbersSteam boiler

0 1 2 3 4 5


Material change

Design change

Others

numbers

Control system

0 5 10 15


Material change

Design change

Others

numbers

2.LNG LOADING ARM and GAS RETURN ARM

A. Type

0

50

100

150

LNGunloading

arm

Gas returnarm

num

bers

B.Capacity Outer－diameter

0

50

100

150

200～299 300～399 400～(mm)

num

bers

C. Date of installation

0

10

20

30

40

50

60

70

1960s 1970s 1980s 1990s 2000s

num

bers

D. Operating hours

0 20 40 60 80 100

10,000～19,999

20,000～29,999

30,000～39,999

40,000～49,999

50,000～

TOTAL

(hours)

numbers

F. Replacement

0

50

100

150

NO YES

num

bers

E.Manufacturer

0 20 40 60 80 100

A

B

C

D

E

F

numbers

A. Material (1)Piping

0

5

10

15

20

25

30

Carbon steel Stainlesssteel

Aluminiumalloy

Others

numbersA. Material (2)Joint

0

5

10

15

20

25

30

Carbonsteel

Stainlesssteel

Aluminiumalloy

Others

numbers

B.Maintenance Methord (1)Piping

0 5 10 15 20 25 30

Time Based Maintenance

Condition Based Maintenance

Break Down Maintenance

Life Cycle Cost evaluation

Others

numbers

C.Type of deterioration Mode (1)Piping

0

5

10

15

20

Corrosion Abrasion Deformation Others

numbers

C.Type of deterioration Mode (2)Joint

02468

1012141618


numbers

D.Diagnosis Methord (1)Piping

0 5 10 15 20 25 30

Liquid penetration test

Visual inspection

Dimensｉｏｎ

Leak test

Performance test

Others

numbers

D.Diagnosis Methord (2)Joint

0 5 10 15 20 25 30


Visual inspection

Dimensｉｏｎ

Leak test

Performance test

Others

numbers

B.Maintenance Methord (2)Joint

0 5 10 15 20 25 30





Others

numbers

E.Regular,scheduled and preventivemaintenance (1)Piping

0

5

10

15

20

Painting Cleaning Partsexchange

Others

numbers

E.Regular,scheduled and preventivemaintenance (2)Joint

0

5

10

15

20


Others

numbers

A.Reason for replacement

0

5

10

15

20


numbers

C.Years of operation before replacement

0

2

4

6

8

10

14 16 17 19 20 25

years

numbers

D.Type of replacement

0 5 10 15 20 25

Replaced with samedesigned equipment

Material change

Design change

Others

numbers

A.Repaired section or part

0

10

20

30

40

Piping Joint Others

num

bers

B.Deterioration mode

0

10

20

30


numbers

D.Years of operation before deterioration

0

10

20

30

40

<5 <10 <15 <20 <25 ≧25years

numbers

C.Corrective measure

0 10 20 30 40


Welding repair

Material change

Design change

Others

numbers

B.Deteriorated section or part

0

5

10

15

20

Piping Joint Others

numbers

3.LNG VAPORIZER

A. .Type

0 50 100 150 200

Open rack vaporizer (ORV)

Submerged combustionvaporizer (SCV)

Shell and Tube heatexchanger

numbers B.Capacity(t/h)

0

20

40

60

80

100

120

～49 50～99 100～149 150～199 200～249 250～(t/h)

numbers

C. Installation year

0

20

40

60

80

100

120

1960s 1970s 1980s 1990s 2000s

numbers

D. Operating hours

0 20 40 60 80 100

～4,999

5,000～9,999

10,000～19,999

20,000～29,999

30,000～39,999

40,000～49,999

50,000～99,999

100,000～149,999

150,000～199,999

200,000～

operationhours

numbers

F. Manufacturer

0 30 60 90 120 150

ABCDEFGHIJKLMNOP

numbers

E. Replacement

0

50

100

150

200

250

300

NO YES

num

bers

A.Material(1)Surface of heat Exchanger tube(ORV)

0 5 10 15 20 25

Carbon steelStainless steelAluminum alloyTitanium alloy

ConcreteOthers

numbers

A.Material(1)Surface of heat Exchanger tube(STHE)

0 5 10 15 20

Carbon steel

Stainless steel

Aluminum alloy

Titanium alloy

Concrete

Others

numbers

A.Material(2)Tube at bottom LNGHeader(ORV)

0 5 10 15 20 25

Carbon steelStainless steel

Aluminum alloyTitanium alloy

ConcreteOthers

numbers

A.Material(3)Extermal shell

(Shell and Tube heart exchanger)

0 5 10 15 20


ConcreteOthers

numbers

A.Material (4)Burmer unit(SCV)

0 5 10 15 20


ConcreteOthers

numbers

A.Material (5)Water bath(SCV)

0 5 10 15 20

Carbon steel

Stainless steel

Aluminum alloy

Titanium alloy

Concrete

Others

numbers

A.Material(6)Blower(SCV)

0 5 10 15 20


ConcreteOthers

numbers

A.Material(1)Surface of heat Exchanger tube(SCV)

0 5 10 15 20


ConcreteOthers

numbers

B.Maintenance method (1)Surface of heat Exchanger tube(ORV)

0

5

10

15

20

TimeBased

ConditionBased

BreakDown

LifeCycle

Others

num

bers

B.Maintenance method (1)Surface of heat Exchanger tube(SCV)

0

5

10

15

20

TimeBased

ConditionBased

BreakDown

LifeCycle

Others

num

bers

B.Maintenance method (1)Surface of heat Exchanger tube(STHE)

0

5

10

15

20

TimeBased

ConditionBased

BreakDown

LifeCycle

Others

num

bers

B.Maintenance method(2)Tube at bottom LNGHeader(ORV)

0

5

10

15

20

TimeBased

ConditionBased

BreakDown

LifeCycle

Others

num

bers

B.Maintenance method(3)Extermal shell

(Shell and Tube heart exchange)

0

5

10

15

20

TimeBased

ConditionBased

BreakDown

LifeCycle

Others

num

bers

B.Maintenance method(4)Burmer unit(SCV)

0

5

10

15

20

TimeBased

ConditionBased

BreakDown

LifeCycle

Others

num

bers

B.Maintenance method(5)Water bath(SCV)

0

5

10

15

20

TimeBased

ConditionBased

BreakDown

LifeCycle

Others

num

bers

B.Maintenance method (6)Blower(SCV)

0

5

10

15

20

TimeBased

ConditionBased

BreakDown

LifeCycle

Others

num

bers

C.Type of deterioration mode (1)Surface of heat Exchanger tube(STHE)

0 5 10 15 20

Corrosion

Crack

Abrasion

Damage by external stress

Others

numbers

C.Type of deterioration mode (1)Surface of heat Exchanger tube(ORV)

0 5 10 15 20

Corrosion

Crack

Abrasion


Others

numbers

C.Type of deterioration mode (1)Surface of heat Exchanger tube(SCV)

0 5 10 15 20

Corrosion

Crack

Abrasion


Others

numbers

C.Type of deterioration mode (2)Tube at bottom LNGHeader(ORV)

0 5 10 15 20

Corrosion

Crack

Abrasion


Others

numbers

C.Monitor deterioration mode(3)Extermal shell

(Shell and Tube heart exchaner)

0 5 10 15 20

Corrosion Crack

Abrasion Damage by external stress

Others

numbers

C.Monitor deterioration mode(4)Burmer unit(SCV)

0 5 10 15 20

Corrosion

Crack

Abrasion


Others

numbers

CType of deterioration mode (5)Water bath(SCV)

0 5 10 15 20

Corrosion

Crack

Abrasion


Others

numbersC.Type of deterioration mode

(6)Blower(SCV)

0 5 10 15 20

Corrosion

Crack

Abrasion


Others

numbers

D.Diagnosis method (1)Surface of heat Exchanger tube(ORV)

0 5 10 15 20 25


Visual inspectionTube or shell thickness

inspectionLeak test

Performance test

Others

numbers

D.Diagnosis method (2)Tube at bottom LNGHeader(ORV)

0 5 10 15 20 25



inspectionLeak test

Performance test

Others

numbers

D.Diagnosis method (3)Extermal shell(Shell and Tube heat exchanger)

0 5 10 15 20



inspectionLeak test

Performance test

Others

numbers

D.Diagnosis method (4)Burner unit(SCV)

0 5 10 15 20



inspectionLeak test

Performance test

Others

numbers

D.Diagnosis method (5)Water bath(SCV)

0 5 10 15 20



inspectionLeak test

Performance test

Others

numbers

D.Diagnosis method (6)Blower(SCV)

0 5 10 15 20



inspectionLeak test

Performance test

Others

numbers

D.Diagnosis method(1)Surface of heat Exchanger tube(SCV)

0 5 10 15 20



inspectionLeak test

Performance test

Others

numbers

D.Diagnosis method(1)Surface of heat Exchanger tube(STHE)

0 5 10 15 20



inspectionLeak test

Performance test

Others

numbers

E.Regular,scheduled and preventivemaintenance

(1)Surface of heat Exchanger tube(SCV)

0 5 10 15 20

Special Coating

Painting

Catheodic protection

Cleaning

Parts exchange

Others

numbers

E.Regular,scheduled and preventive maintenance(1)Surface of heat Exchanger tube(STHE)

0 5 10 15 20

Special Coating

Painting


Cleaning

Parts exchange

Others

numbers


(2)Tube at bottom LNGHeader(ORV)

0 5 10 15 20

Special Coating

Painting


Cleaning

Parts exchange

Others

numbers

E.Regular,scheduled and preventive maintenance(3)External shell(Shell and Tube heat exchanger)

0 5 10 15 20

Special Coating

Painting


Cleaning

Parts exchange

Others

numbers


(4)Burner unit(SCV)

0 5 10 15 20

Special Coating

Painting


Cleaning

Parts exchange

Others

numbers


(5)Water bath(SCV)

0 5 10 15 20

Special CoatingPainting

Catheodic protectionCleaning

Parts exchangeOthers

numbers


(6)Blower(SCV)

0 5 10 15 20

Special Coating

Painting


Cleaning

Parts exchange

Others

numbers


(1)Surface of heat Exchanger tube(ORV)

0 5 10 15 20

Special Coating

Painting


Cleaning

Parts exchange

Others

numbers


0 5 10 15 20 25 30

Corrosion

Crack

Abrasion

Damage by externalstress

Others

numbers

B.Deteriorated section or part

0 5 10 15 20

Surface of heat exchanger tube (Alltypes)

Tube at bottom LNG header (ORV)

External shell (shell and tube heatexchanger)

Burner unit (SCV)

Water bath (SCV)

Blower (SCV)

Others

numbers

Years of operation before replacement

0

5

10

15

＜5 ＜10 ＜15 ＜20 ≧20 Othersyears

numbers

C.Type of replacement

0 5 10 15 20 25 30 35

Replaced with same designedequipment

Material change

Design change

Parts exchange

Others

numbers

A.Repaired secrion or part

0 10 20 30 40 50

Surface of heat exchanger tube

Tube at bottom LNG header(ORV)

External shell(shell and tube heatexchanger)

Burner unit(SCV)

Water bath(SCV)

Blower(SCV)

Others

numbersB.Deterriration mode

0 10 20 30 40

Corrosion

Crack

Abrasion

Damage by externalstress

Others

numbers

C.Corrective measere

0 10 20 30 40 50

Replaced with same designed equipment

Welding repair

Replacement of heating tube

Repair by thermal-sprayed film

Parts exchange

Plugging of heating tube

Mending

Material change

Design change

Others

numbersD.Years of operation before

deterioration

0

10

20

30

40

50

<5 <10 <15 <20 25< ≧25

years

numbers

4.LNG PUMP

A. Capacity　(t/h)

0

100

200

300

0～99 100～199 200～299 300～399(t/h)

numbersB. Date of installation

0

100

200

300

1960ｓ 1970s 1980s 1990s 2000s

numbers

C. Operating hours

0 50 100 150 200

～19,999

20,000～39,999

40,000～59,999

60,000～79,999

80,000～99,999

100,000～

Others

(hours)

numbers

E. Replacement

0100200300400500600

NO YES

num

bers

D. Manufacturer

0 50 100 150 200 250

A

B

C

D

E

F

G

H

I

J

K

numbers

B.Maintenance method (3) Balancing disc

0 5 10 15 20

Time Based MaintenanceCondition Based

MaintenanceBreak Down Maintenance


Others

numbers

B.Maintenance method (1) Shaft

0 5 10 15 20





Others

numbers

B.Maintenance method (2) Impeller

0 5 10 15 20





Others

numbers

B.Maintenance method (4) Bearing

0 5 10 15 20

Time BasedMaintenance

ConditionBased

Break DownMaintenance

Life CycleCostOthers

numbers

A.Material (1) Shaft

0

5

10

15

20

25

Carbonsteel

Stainlesssteel

Aluminiumalloy

Others

numbers A.Material (2) Impeller

0

5

10

15

20

25

Carbonsteel

Stainlesssteel

Aluminiumalloy

Others

numbers

A.Material (3) Balancing disc

0

5

10

15

20

25

Carbonsteel

Stainlesssteel

Aluminiumalloy

Others

numbersA.Material (4) Bearing

0

5

10

15

20

25

Carbonsteel

Stainlesssteel

Aluminiumalloy

Others

numbers

C.Type of deterrioration mode(3)Balancing disc

0

5

10

15

20

25

Abras

ion

Curva

ture

Corrosio

n

Crack

Deformation

Others

numbers

D.Diagnosis method (1)Shaft

0 10 20 30


Visual inspection

Size check

Others

numbers

C.Type of deterrioration mode(4)Bearing

0

5

10

15

20

25

Abras

ion

Curva

ture

Corrosio

n

Crack

Deformation

Others

numbers

CType of deterrioration mode (1)Shaft

0

5

10

15

20

25

Abr

asion

Curva

ture

Corro

sion

Crack

Defor

mation

Other

s

numbers

D.Diagnosis method (2) Impeller

0 5 10 15 20 25


Visual inspection

Size check

Others

numbers

D.Diagnosis method (4)Bearing

0 5 10 15 20 25

Liquidpenetration

Visualinspection

Size check

Others

numbersD.Diagnosis method (3)Balancing disc

0 5 10 15 20 25


Visual inspection

Size check

Others

numbers

E.Regular,scheduled andti i t

E.Regular,scheduled and E.Regular,scheduled andti i t

C.Type of deterrioration mode (2)Impeller

0

5

10

15

20

25

Abr

asion

Curva

ture

Corro

sion

Crack

Defor

mation

Other

s

numbers


0 5 10 15 20 25 30

Abrasion

Curvature

Corrosion

Crack

Deformation

Others

numbers

B.Deteriorated section or parts

0 5 10 15 20 25 30

Shaft

Impeller

Balancing disc

Bearing

Others

numbers

D.Type of Replacement

0 5 10 15 20 25 30


Material change

Design change

Others

numbers

C. Years of operation before replacement

0

2

4

6

8

10

1 4 22 23 32years

numbers

E.Regular,scheduled andpreventive maintenance

(3)Balancing disc

0

5

10

15

20

Cleaning PartsExchange

Others

numbers


(4)Bearing

0

5

10

15

20

25

30


Others

numbers

E.Regular,scheduled andpreventive maintenance (1)Shaft

0

5

10

15

20

25


Others

numbers


(2)Impeller

0

5

10

15

20

25


Others

numbers


0 20 40 60 80 100

Shaft

Impeller

Balancing disc

Bearing　(Except for routineexchange)

Others

numbers B.Deterioration mode

0

50

100

150

200

Abrasion Curvature CorrosionDeformation Others

numbers

C.Correctiv emeasure

0 50 100


Parts exchange

Material change

Design change

Others

numbersD.Years of operation before deterioratio

0

50

100

150

200

<5 <10 <15 <20 <25 ≧25

years

numbers

.

5.BOG COMPRESSOR

A. Material (3)Piston ring

0

5

10

15

20

Carbonsteel

Stainlesssteel

Aluminumalloy

Resin Others

numbersA. Material (4)Piston rod

0

5

10

15

20

Carbonsteel

Stainlesssteel

Aluminumalloy

Resin Others

numbers

A. Material (1)Crank shaft

0

5

10

15

20

Carbonsteel

Stainlesssteel

Aluminumalloy

Resin Others

numbersA. Material (2)Piston

0

5

10

15

20

Carbonsteel

Stainlesssteel

Aluminumalloy

Resin Others

numbers

A. Capacity(m3N/h)

0 10 20 30 40

～4,999

5,000～9,999

10,000～14,999

15,000～19,999

20,000～

(m3N)

numbers

B. Date of installation

0

10

20

30

40

50

1960s 1970s 1980s 1990s 2000s Others

numbers

C. Operating hours

0 5 10 15 20

～19,999

20,000～39,999

40,000～59,999

60,000～79,999

80,000～99,999

100,000～

Others

(hours)

numbers

D. Manufacturer

0 20 40 60 80

A

B

C

D

E

F

G

H

I

numbersE. Replacement

0

20

40

60

80

100

NO YES

num

bers

A. Material (7)Snubber tank

0

5

10

15

20

Carbonsteel

Stainlesssteel

Aluminumalloy

Resin Others

numbersA. Material (8)Cylinder support

0

5

10

15

20

Carbonsteel

Stainlesssteel

Aluminumalloy

Resin Others

numbers

A. Material (6)Cylinder liner

0

5

10

15

20

Carbonsteel

Stainlesssteel

Aluminumalloy

Resin Others

numbersA. Material (5)Connecting rod

0

5

10

15

20

Carbonsteel

Stainlesssteel

Aluminumalloy

Resin Others

numbers

2

68

B.Maintenance method(1)Crank shaft

0 5 10 15 20 25


Condition BasedMaintenance



Others

numbers

B.Maintenance method(2)Piston

0 5 10 15 20 25

Time BasedMaintenance

ConditionBased

Break DownMaintenance

Life CycleCost

Others

numbers

B.Maintenance method(3)Piston ring

0 5 10 15 20 25





Others

numbers

B.Maintenance method(4)Piston rod

0 5 10 15 20 25





Others

numbers

B.Maintenance method(7)Snubber tank

0 5 10 15 20





Others

numbers

B.Maintenance method(8)Cylinder support

0 5 10 15 20 25





Others

numbers

B.Maintenance method(5)Connecting rod

0 5 10 15 20 25





Others

numbers

B.Maintenance method(6)Cylinder liner

0 5 10 15 20 25





Others

numbers

C Type of deteriorartion mode C Type of deteriorartion mode

C.Type of deteriorartion mode(4)Piston rod

0

5

10

15

20

Abr

asion

Cur

vatu

re

Cor

rosio

nCra

ck

Defor

mation

Other

s

numbers

C.Type of deteriorartion mode(3)Piston ring

0

5

10

15

20

25

Abr

asion

Cur

vatu

re

Cor

rosio

nCra

ck

Defor

mation

Other

s

numbers

C.Type of deteriorartion mode(1)Crank shaft

0

5

10

15

20

Abr

asion

Cur

vatu

re

Cor

rosio

nCra

ck

Defor

mation

Other

s

numbers

C.Type of deteriorartion mode(2)Piston

0

5

10

15

20

Abr

asion

Cur

vatu

re

Cor

rosio

nCra

ck

Defor

mation

Other

s

numbers

C.Type of deteriorartion mode(8)Cylinder support

0

5

10

15

20

Abr

asion

Cur

vatu

re

Cor

rosio

nCra

ck

Defor

mation

Other

s

numbers

C.Type of deteriorartion mode(7)Snubber tank

0

5

10

15

20

Abr

asion

Cur

vatu

re

Cor

rosio

nCra

ck

Defor

mation

Other

s

numbers

C.Type of deteriorartion mode(5)Connecting rod

0

5

10

15

20

Abr

asion

Cur

vatu

re

Cor

rosio

nCra

ck

Defor

mation

Other

s

numbers

C.Type of deteriorartion mode(6)Cylinder liner

0

5

10

15

20

25

Abr

asion

Cur

vatu

re

Cor

rosio

nCra

ck

Defor

mation

Other

s

numbers

D.Diagnosis method (1)Crank shaft

0 5 10 15 20 25


Visual inspection

Size inspection

Wall thickness inspection

Others

numbers

D.Diagnosis method (2)Piston

0 5 10 15 20


Visual inspection

Size inspection


Others

numbers

D.Diagnosis method　(3)Piston ring

0 5 10 15 20


Visual inspection

Size inspection


Others

numbers

D.Diagnosis method (4)Piston rod

0 5 10 15 20 25


Visual inspection

Size inspection


Others

numbers

D.Diagnosis method (5)Connecting rod

0 5 10 15 20


Visual inspection

Size inspection


Others

numbers

D.Diagnosis method (6)Cylinder liner

0 5 10 15 20 25


Visual inspection

Size inspection


Others

numbers

D.Diagnosis method (7)Snubber tank

0 5 10 15 20


Visual inspection

Size inspection


Others

numbers

D.Diagnosis method (8)Cylinder support

0 5 10 15 20


Visual inspection

Size inspection


Others

numbers

E.Regular, scheduled and preventive E.Regular, scheduled and preventiv E.Regular, scheduled and


0 1 2 3 4 5

Abrasion

Curvature

Corrosion

Crack

Deformation

Others

numbersB. Years of operationbefore replacement

0

1

2

3

4

5

5 10 14years

num

bers

C.Type of Replacement

0 1 2 3 4 5numbers

E.Regular, scheduled andpreventive maintenance

(4)Piston rod

0

5

10

15

20


Others

num

bers


(5)Connecting rod

0

5

10

15

20

PaintingCleaning Partsexchange

Others

num

bers


(6)Cylinder liner

0

5

10

15

20


Others

num

bers

E.Regular, scheduled and preventivemaintenance

(1)Crank shaft

0

5

10

15

20

25


Others

num

bers


(2)Piston

0

5

10

15

20

25


Others

num

bers


(3)Piston ring

0

5

10

15

20

25


Others

num

bers


(7)Snubber tank

0

5

10

15

20


Others

num

bers

E.Regular, scheduled andpreventive　maintenance

(8)Cylinder support

0

5

10

15

20


Others

num

bers

C ype o ep ace e t

0 1 2 3 4 5

Replaced with same designedequipment

Material change

Design change

Others

numbers


0 10 20 30 40

Crank shaft

PistonPiston ring(Except for

routine exchange)Piston rod

Connecting rod

Cylinder liner

Snubber tank

Cylinder support

Others

numbersB.Deterioration mode

0 20 40 60

Abrasion

Curvature

Corrosion

Crack

Deformation

Others

numbers

C.Corrective　measure

0 5 10 15 20 25 30

Replacement with the samedesign type

Repair

Parts exchange

Material change

Design change

Others

numbersD.Years of operation before

deterioration

0

10

20

30

40

<5 <10 <15 <20 <25 ≧25years

numbers

Yes No total Yes No

Acid gas remover 0 4 4 0% 100% (N=4)

Dehydrator 0 5 5 0% 100% (N=5)

Main heat exchanger 1 4 5 20% 80% (N=5)

Refrigerating equipment 2 3 5 40% 60% (N=5)

Control system 3 2 5 60% 40% (N=5)

2.If the entire unit has been replaced, please select the reason for the replacement.

Abrasion Curvature Corrosion Crack Deformation Others total Abrasion Curvature Corrosion Crack Deformati

on Others

Acid gas remover 0 0 0 0 0 0 0 0% 0% 0% 0% 0% 0% (N=0)

Dehydrator 0 0 0 0 0 0 0 0% 0% 0% 0% 0% 0% (N=0)

Main heat exchanger 0 0 0 0 0 1 1 0% 0% 0% 0% 0% 100% (N=1)

Refrigerating equipment 1 0 1 1 0 0 3 50% 0% 50% 50% 0% 0% (N=2)

Control system 0 0 0 0 0 4 4 0% 0% 0% 0% 0% 100% (N=4)

3. If the entire unit has been replaced, please select the method for the replacement

Replacement with the

samedesigned

equipment

Materialchange

Designchange Others total

Replacement with the

samedesigned

equipment

Materialchange

Designchange Others

Acid gas remover 0 0 0 0 0 0% 0% 0% 0% (N=0)

Dehydrator 0 0 0 0 0 0% 0% 0% 0% (N=0)

Main heat exchanger 2 0 0 0 2 100% 0% 0% 0% (N=2)

Refrigerating equipment 2 0 0 0 2 100% 0% 0% 0% (N=2)

Control system 0 0 3 1 4 0% 0% 75% 25% (N=4)

QA:Please provide replacement information concerning time-related deterioration facilities at the terminal. The target facilities are as follows

1.Please indicate whether the entire unit has been replaced or not

COUNT

UNITSCOUNT PORTION

UNITS

UNITS

Appendix 2. Results of the Questionnaire Sent to LNG Liquefaction Terminals

COUNT PORTION

PORTION

QB　1.LNG LOADING ARM and GAS RETURN ARM

Table 1 (List of applicable unit)

■ Type (N=6) ■ Capacity Outer-diameter(mm) (N=6) ■ Date of installation (N=6)

COUNT PORTION COUNT PORTION COUNT PORTION

LNG loading arm 32 78% 1 2% 14 34%

Gas return arm 9 22% 3 7% 10 24%

TOTAL 41 100% 3 7% 17 41%

4 10% 41 100%

20 49%

10 24%

41 100%

■ Operating hours (N=4) ■ Manufacturer (N=6) ■ Replacement (N=2)


～9,999 17 68% 19 46% 8 44%

10,000～19,999 0 0% 22 54% 10 56%

20,000～29,999 0 0% 41 100% 18 44%

30,000～ 8 32%

TOTAL 25 100%

Table2 (List of important section or part in maintenance)

A. Material

Carbonsteel

Stainlesssteel

Aluminiumalloy Others TOTAL Carbon

steelStainless

steelAluminium

alloy Others TOTAL

(1)Piping 0 5 0 0 5 0% 100% 0% 0% 100% (N=5)

(2)Joint 0 3 0 2 5 0% 60% 0% 40% 100% (N=5)

B. Maintenance Method

TimeBased

Maintenance

ConditionBased

Maintenance

BreakDown

Maintenance

Life CycleCost

evaluationOthers TOTAL

TimeBased

Maintenance

ConditionBased

Maintenance

BreakDown

Maintenance

Life CycleCost

evaluationOthers

(1)Piping 4 1 1 0 0 6 100% 25% 25% 0% 0% (N=4)

(2)Joint 2 3 0 0 0 5 50% 75% 0% 0% 0% (N=4)

C. Monitoring deterioration Mode

Corrosion Abrasion Deformation Others TOTAL Corrosion Abrasion Deformati

on Others

(1)Piping 1 0 2 2 5 25% 0% 50% 50% (N=4)

(2)Joint 1 1 3 1 6 25% 25% 75% 25% (N=4)

D. Diagnosis Method

Liquidpenetration

test

Visualinspection

Dimension check Leak test Performa

nce test Others TOTALLiquid

penetrationtest

Visualinspection

Dimension check Leak test Performa

nce test Others

(1)Piping 1 4 1 3 0 0 9 20% 80% 20% 60% 0% 0% (N=5)

(2)Joint 1 3 2 2 1 0 9 20% 60% 40% 40% 20% 0% (N=5)

E. Regular, scheduled and preventive maintenance

Painting Cleaning Partsexchange Others TOTAL Painting Cleaning Parts

exchange Others

(1)Piping 2 2 2 1 7 50% 50% 50% 25% (N=4)

(2)Joint 1 3 5 0 9 20% 60% 100% 0% (N=5)

NO

YES

TOTAL

PORTION

PORTION

PORTION

COUNT PORTION

COUNT

COUNT

TOTAL

305

380

392

1970s

1980s

1990s

COUNT

147

294

TOTAL

Others

A

B

TOTAL

COUNT PORTION

Table 3 (List of replaced unit )

A. Reason for replacement (N=3) B. Deteriorated section or part (N=3) C. Years of operation before replacement (N=3)


Corrosion 2 12% 0 0% 10 67%

Abrasion 0 0% 15 58% 1 7%

Deformation 12 71% 11 42% 1 7%

Others 3 18% 26 100% 3 20%

TOTAL 17 100% 15 100%

D. Type of replacement (N=3)

COUNT PORTION

Replaced with samedesigned equipment 0 0%

Material change 3 20%

Design change 12 80%

Others 0 0%

TOTAL 15 100%

Table4 (List of record of repair work)

A.Repaired section or part (N=3) B.Deterioration mode (N=3) C. Corrective measure (N=3)


Piping 12 24% 0 0% 20 42%

Joint 15 31% 10 18% 3 6%

Others 22 45% 32 58% 3 6%

TOTAL 49 100% 13 24% 12 25%

55 100% 10 21%

48 100%

(N=3)

COUNT PORTION

<5 10 22%

<10 20 44%

<15 13 29%

<20 2 4%

<25 0 0%

25≦ 0 0%

TOTAL 45 100%

TOTAL

Others

TOTAL

Replaced with same designedequipmentWelding repair

Material change

Design change

Others

Corrosion

Abrasion

Deformation

Piping

Joint

Others

TOTAL

TOTAL

17

19.2

19.5

20

D.Years of operation before deterioration

2.SEA WATER PUMP


■Capacity(t/h) (N=4) ■Date of installation (N=5) ■Operating hours (N=2)


8.8 8 38% 1 4% 2 14%

29.2 6 29% 18 67% 0 0%

33 6 29% 1 4% 3 21%

5000 1 5% 7 26% 9 64%

TOTAL 21 100% 27 100% 14 100%

■Manufacturer (N=5) ■Replacement (N=3)

COUNT PORTION COUNT PORTION

A 3 11% 8 50%

B 6 22% 8 50%

C 8 30% 16 100%

D 1 4%

E 6 22%

F 2 7%

G 1 4%

TOTAL 27 100%

A. Material

Carbonsteel

Stainlesssteel Others Total Carbon

steelStainless

steel Others Total

(1)Casing 3 0 1 4 75% 0% 25% 100% (N=4)

(2)Shaft 0 3 1 4 0% 75% 25% 100% (N=4)

(3)Impeller 2 1 1 4 50% 25% 25% 100% (N=4)

(4)Bearing 1 1 1 3 33% 33% 33% 100% (N=3)

(5)Gear box 0 0 0 0 0% 0% 0% 0% (N=0)

(6)Others 0 0 1 1 0% 0% 100% 100% (N=1)

B. Maintenance method

TimeBased

Maintenance

ConditionBased

Maintenance

BreakDown

Maintenance

Life CycleCost

evaluationOthers Total

TimeBased

Maintenance

ConditionBased

Maintenance

BreakDown

Maintenance

Life CycleCost

evaluationOthers

(1)Casing 3 2 1 0 0 6 75% 50% 25% 0% 0% (N=4)

(2)Shaft 3 2 1 0 0 6 75% 50% 25% 0% 0% (N=4)

(3)Impeller 3 2 1 0 0 6 75% 50% 25% 0% 0% (N=4)

(4)Bearing 3 2 1 0 0 6 75% 50% 25% 0% 0% (N=4)

(5)Gear box 0 0 0 0 0 0 0% 0% 0% 0% 0% (N=0)

(6)Others 1 0 0 0 0 1 100% 0% 0% 0% 0% (N=1)

C. Monitor of deterioration mode

Abrasion Curvature Corrosion Crack Deformation Others Total Abrasion Curvature Corrosion Crack Deformati

on Others

(1)Casing 1 1 2 2 1 0 7 50% 50% 100% 100% 50% 0% (N=2)

(2)Shaft 1 0 1 0 1 1 4 50% 0% 50% 0% 50% 50% (N=2)

(3)Impeller 1 0 1 1 0 0 3 50% 0% 50% 50% 0% 0% (N=2)

(4)Bearing 1 0 0 0 0 0 1 100% 0% 0% 0% 0% 0% (N=1)

(5)Gear box 0 0 0 0 0 0 0 0% 0% 0% 0% 0% 0% (N=0)

(6)Others 0 0 0 0 0 0 0 0% 0% 0% 0% 0% 0% (N=0)

TOTAL

150,000～199,999

200,000～

TOTAL

NO

YES

1960s

1970s

～99,999

100,000～149,999

COUNT PORTION

Table 2(List of important section or part in maintenannce)

COUNT

COUNT

PORTION

1980s

1990s

TOTAL

PORTION

D. Diagnosis method

Liquidpenetratio

n test

Visualinspection

Sizecheck Others Total

Liquidpenetratio

n test

Visualinspection

Sizecheck Others

(1)Casing 2 4 1 0 7 50% 100% 25% 0% (N=4)

(2)Shaft 1 2 2 0 5 33% 67% 67% 0% (N=3)

(3)Impeller 1 3 1 0 5 33% 100% 33% 0% (N=3)

(4)Bearing 0 3 2 0 5 0% 100% 67% 0% (N=3)

(5)Gear box 0 0 0 0 0 0% 0% 0% 0% (N=0)

(6)Others 0 1 1 0 2 0% 100% 100% 0% (N=1)



Specialcoating

Cathodicprotection Others Total Painting Cleaning Parts

exchangeSpecialcoating

Cathodicprotection Others

(1)Casing 3 2 2 2 1 0 10 100% 67% 67% 67% 33% 0% (N=3)

(2)Shaft 0 2 3 0 0 0 5 0% 50% 75% 0% 0% 0% (N=4)

(3)Impeller 0 2 3 0 0 0 5 0% 50% 75% 0% 0% 0% (N=4)

(4)Bearing 0 1 4 0 0 1 6 0% 25% 100% 0% 0% 25% (N=4)

(5)Gear box 0 0 0 0 0 0 0 0% 0% 0% 0% 0% 0% (N=0)

(6)Others 0 0 1 0 0 0 1 0% 0% 100% 0% 0% 0% (N=1)

Table 3 (List of replaced unit)

A. Reason for eplacement (N=2) B. Deteriorated section or part (N=3)


Abrasion 0 0% 6 12% 6 30%

Curvature 1 5% 15 31% 6 30%

Corrosion 14 67% 14 29% 8 40%

Crack 0 0% 14 29% 20 100%

Deformation 6 29% 0 0%

Others 0 0% 0 0%

TOTAL 21 100% 49 100%


COUNT PORTION



Design change 7 47%

Others 0 0%

TOTAL 15 100%


A.Repaired section or part (N=3) B.Deterioration mode (N=4) C.Corrective measure (N=4)


Casing 12 29% 8 14% 8 24%

Shaft 14 33% 6 10% 0 0%

Impellert 8 19% 26 45% 13 38%Bearing (Except forroutine exchange) 8 19% 12 21% 0 0%

Gear box 0 0% 6 10% 7 21%

Others 0 0% 0 0% 6 18%

TOTAL 42 100% 58 100% 34 100%

Material change

Design change

Others

Total


Parts exchange

Crack

Deformation

Others

TOTAL

Abrasion

Curvature

Corrosion

Gear box

Others

TOTAL

17

25

Others

TOTAL

Casing

Shaft

Impellert

Bearing

PORTION

PORTION

COUNT

COUNT

C.Years of operation before replacement (N=3)

(N=4)

COUNT PORTION

<5 8 44%

<10 6 33%

<15 0 0%

<20 6 33%

<25 2 11%

25≦ 4 22%

Total 26 100%

D.Years of operation beforedeterioration

3.STEAM BOILER




～99 5 7% 5 7% 2 15%

100～199 43 62% 28 41% 1 8%

200～299 0 0% 26 38% 1 8%

300～399 4 6% 9 13% 6 46%

400～ 9 13% 1 1% 3 23%

Others 8 12% 69 100% 13 100%

TOTAL 69 100%



A 5 7% 28 78%

B 1 1% 8 22%

C 5 7% 36 100%

D 21 30%

E 11 16%

F 22 32%

G 4 6%

TOTAL 69 100%


A. Material

Carbonsteel Others Total Carbon

steel Others

(1)Heat exchanger tube 8 1 9 200% 25% (N=4)

(2)Flue tube, Smoke tube 2 1 3 67% 33% (N=3)

(3)Header tube 7 1 8 175% 25% (N=4)

(4)De-Airator 8 1 9 200% 25% (N=4)

(5)Burner unit 7 2 9 175% 50% (N=4)

(6)Fan 8 6 14 200% 150% (N=4)

(7)Others 15 6 21 750% 300% (N=2)


TimeBased

Maintenance

ConditionBased

Maintenance

BreakDown

Maintenance

Life CycleCost

evaluationOthers Total

TimeBased

Maintenance

ConditionBased

Maintenance

BreakDown

Maintenance

Life CycleCost

evaluationOthers

(1)Heat exchanger tube 6 0 7 0 0 13 150% 0% 175% 0% 0% (N=4)

(2)Flue tube, Smoke tube 0 1 3 0 0 4 0% 33% 100% 0% 0% (N=3)

(3)Header tube 5 1 7 0 0 13 125% 25% 175% 0% 0% (N=4)

(4)De-Airator 6 1 7 0 0 14 150% 25% 175% 0% 0% (N=4)

(5)Burner unit 6 2 7 0 0 15 150% 50% 175% 0% 0% (N=4)

(6)Fan 3 7 2 1 1 14 75% 175% 50% 25% 25% (N=4)

(7)Others 14 5 8 0 1 28 700% 250% 400% 0% 50% (N=2)

NO

YES

TOTAL

1990s

2000s

TOTAL

～49,999

50,000～99,999

100,000～149,999

150,000～199,999

200,000～

TOTAL

1960s

1970s

1980s

COUNT

COUNT PORTION

PORTION

C. Monitor of deterioration mode

Abrasion Curvature Corrosion Crack Deformation Others Total Abrasion Curvature Corrosion Crack Deformati

on Others

(1)Heat exchanger tube 0 0 8 7 2 0 17 0% 0% 267% 233% 67% 0% (N=3)

(2)Flue tube, Smoke tube 0 0 2 1 1 0 4 0% 0% 100% 50% 50% 0% (N=2)

(3)Header tube 0 0 2 1 1 5 9 0% 0% 67% 33% 33% 167% (N=3)

(4)De-Airator 1 0 8 2 2 0 13 25% 0% 200% 50% 50% 0% (N=4)

(5)Burner unit 0 1 6 1 1 1 10 0% 50% 300% 50% 50% 50% (N=2)

(6)Fan 0 1 1 1 2 2 7 0% 25% 25% 25% 50% 50% (N=4)

(7)Others 0 0 10 1 5 0 16 0% 0% 500% 50% 250% 0% (N=2)

D. Diagnosis method

Liquidpenetration

test

Visualinspection

Sizecheck

Thicknessinspection Leak test Others Total

Liquidpenetration

test

Visualinspection

Sizecheck

Thicknessinspection Leak test Others

(1)Heat exchanger tube 1 8 1 7 7 0 24 33% 267% 33% 233% 233% 0% (N=3)

(2)Flue tube, Smoke tube 0 2 0 1 1 0 4 0% 100% 0% 50% 50% 0% (N=2)

(3)Header tube 0 7 0 1 1 0 9 0% 233% 0% 33% 33% 0% (N=3)

(4)De-Airator 1 8 0 7 7 0 23 33% 267% 0% 233% 233% 0% (N=3)

(5)Burner unit 1 7 0 0 0 1 9 50% 350% 0% 0% 0% 50% (N=2)

(6)Fan 1 4 2 0 0 6 13 25% 100% 50% 0% 0% 150% (N=4)

(7)Others 0 15 5 0 10 1 31 0% 750% 250% 0% 500% 50% (N=2)


Painting Cleaning Partsexchange Others Total Painting Cleaning Parts

exchange Others

(1)Heat exchanger tube 2 3 8 0 13 67% 100% 267% 0% (N=3)

(2)Flue tube, Smoke tube 1 2 2 0 5 50% 100% 100% 0% (N=2)

(3)Header tube 1 7 2 0 10 33% 233% 67% 0% (N=3)

(4)De-Airator 1 7 7 0 15 33% 233% 233% 0% (N=3)

(5)Burner unit 0 2 8 0 10 0% 67% 267% 0% (N=3)

(6)Fan 1 2 9 1 13 25% 50% 225% 25% (N=4)

(7)Others 5 5 16 0 26 250% 250% 800% 0% (N=2)

Table 3(List of replaced unit)

A.Reason for replacement (N=3) B.Deteriorated section or parts (N=3) C. Years of operation before replacement (N=3)


Abrasion 0 0% 7 20% 7 41%

Curvature 2 6% 7 20% 3 18%

Corrosion 11 31% 2 6% 1 6%

Crack 7 20% 5 14% 6 35%

Deformation 7 20% 2 6% 17 100%

Others 8 23% 5 14%

Total 35 100% 7 20%

35 100%


COUNT PORTION



Design change 2 12%

Others 0 0%

TOTAL 17 100%

25

TotalBurner unit

Fan

Others

4

5

20

COUNT

COUNT

PORTION

PORTION

Heat exchanger tube

Flue tube, Smoke tube

Header tube

De-Airator

TOTAL

COUNT PORTION


A.Repaired section or part (N=3) B.Deterioration mode (N=3) C.Corrective measure (N=3)


Heat exchanger tube 27 28% 1 2% 6 10%

Flue tube, Smoke tube 11 11% 0 0% 26 43%

Header tube 6 6% 32 48% 6 10%

De-Airator 22 23% 11 17% 6 10%

Burner unit 1 1% 11 17% 17 28%

Fan 15 15% 11 17% 61 100%

Others 15 15% 66 100%

TOTAL 97 100%

(N=3)

COUNT PORTION

<5 23 47%

<10 2 4%

<15 19 39%

<20 0 0%

<25 5 10%

25≦ 0 0%

TOTAL 49 100%

Others

TOTAL


Material change

Design change

Others

TOTAL

Curvature

Corrosion

Crack

Deformation

Abrasion


４.Cycle compressor and driver




～499 27 75% 3 8% 0 0%

500～999 6 17% 7 18% 22 56%

1000～ 3 8% 29 74% 7 18%

TOTAL 36 100% 39 100% 3 8%

0 0%

32 82%



A 24 62% 4 100%

B 5 13% 0 0%

C 6 15% 4 100%

D 2 5%

E 1 3%

F 1 3%

TOTAL 39 100%


A. Material

Carbonsteel

Stainlesssteel Others TOTAL Carbon

steelStainless

steel Others(1)Casing (Cycle compressor) 10 1 0 11 167% 17% 0% (N=6)

(2)Casing (driver) 11 0 0 11 183% 0% 0% (N=6)(3)Rotor (Cycle compressor) 1 8 2 11 17% 133% 33% (N=6)

(4)Rotor (driver) 2 7 2 11 33% 117% 33% (N=6)(5)Bearing (Cycle compressor) 8 1 2 11 133% 17% 33% (N=6)

(6)Bearing(driver) 8 1 2 11 133% 17% 33% (N=6)

(7)Others 0 0 0 0 0% 0% 0% (N=0)


TimeBased

Maintenance

ConditionBased

Maintenance

BreakDown

Maintenance

Life CycleCost

evaluationOthers TOTAL

TimeBased

Maintenance

ConditionBased

Maintenance

BreakDown

Maintenance

Life CycleCost

evaluationOthers

(1)Casing (Cycle compressor) 9 2 2 0 0 13 180% 40% 40% 0% 0% (N=5)

(2)Casing (driver) 10 3 1 0 0 14 200% 60% 20% 0% 0% (N=5)(3)Rotor (Cycle compressor) 10 10 1 0 0 21 167% 167% 17% 0% 0% (N=6)

(4)Rotor (driver) 10 10 1 0 0 21 167% 167% 17% 0% 0% (N=6)(5)Bearing (Cycle compressor) 10 10 1 0 0 21 167% 167% 17% 0% 0% (N=6)

(6)Bearing(driver) 10 10 1 0 0 21 167% 167% 17% 0% 0% (N=6)

(7)Others 0 0 0 0 0 0 0% 0% 0% 0% 0% (N=0)

YES

TOTAL

200,000～

TOTAL

NO

TOTAL

～49,999

50,000～99,999

100,000～149,999

150,000～199,999

1960s

1970s

1980s

COUNT

COUNT

PORTION

PORTION

C.Monitor of deterioration mode

Abrasion Curvature Corrosion Crack Deformation Others TOTAL Abrasion Curvature Corrosion Crack Deformati

on Others(1)Casing (Cycle compressor) 1 1 8 1 1 1 13 20% 20% 160% 20% 20% 20% (N=5)

(2)Casing (driver) 1 1 8 2 1 1 14 20% 20% 160% 40% 20% 20% (N=5)(3)Rotor (Cycle compressor) 1 7 1 2 3 9 23 17% 117% 17% 33% 50% 150% (N=6)

(4)Rotor (driver) 2 7 2 2 3 9 25 33% 117% 33% 33% 50% 150% (N=6)(5)Bearing (Cycle compressor) 7 1 1 1 2 9 21 117% 17% 17% 17% 33% 150% (N=6)

(6)Bearing(driver) 7 1 1 1 2 9 21 117% 17% 17% 17% 33% 150% (N=6)

(7)Others 0 0 0 0 0 0 0 0% 0% 0% 0% 0% 0% (N=0)

D. Diagnosis method

Liquidpenetratio

n test

Visualinspection

Sizecheck Others TOTAL

Liquidpenetratio

n test

Visualinspection

Sizecheck Others

(1)Casing (Cycle compressor) 2 10 1 2 15 40% 200% 20% 40% (N=5)

(2)Casing (driver) 2 10 1 1 14 40% 200% 20% 20% (N=5)(3)Rotor (Cycle compressor) 8 9 8 3 28 133% 150% 133% 50% (N=6)

(4)Rotor (driver) 8 9 8 3 28 133% 150% 133% 50% (N=6)(5)Bearing (Cycle compressor) 1 10 8 3 22 17% 167% 133% 50% (N=6)

(6)Bearing(driver) 1 10 8 3 22 17% 167% 133% 50% (N=6)

(7)Others 0 0 0 0 0 0% 0% 0% 0% (N=0)



Specialcoating

Cathodicprotection 6.TOTAL Painting Cleaning Parts

exchangeSpecialcoating

Cathodicprotection

(1)Casing (Cycle compressor) 8 9 3 1 0 21 160% 180% 60% 20% 0% (N=5)

(2)Casing (driver) 7 9 3 0 0 19 140% 180% 60% 0% 0% (N=5)(3)Rotor (Cycle compressor) 1 8 5 1 0 15 17% 133% 83% 17% 0% (N=6)

(4)Rotor (driver) 1 8 5 1 0 15 17% 133% 83% 17% 0% (N=6)(5)Bearing (Cycle compressor) 1 3 10 1 0 15 17% 50% 167% 17% 0% (N=6)

(6)Bearing(driver) 1 3 10 1 0 15 17% 50% 167% 17% 0% (N=6)

(7)Others 0 0 0 0 0 0 0% 0% 0% 0% 0% (N=0)

Table 3 (List of replaced unit)

A. Reason forreplacement (N=3) B. Deteriorated section or part (N=3) C. Years of operation before replacement (N=3)


Abrasion 0 0% 0 0% 3 13%

Curvature 0 0% 3 13% 18 78%

Corrosion 18 44% 0 0% 2 9%

Crack 18 44% 3 13% 23 100%

Deformation 0 0% 0 0%

Others 5 12% 18 75%

TOTAL 41 100% 24 100%

C. Type of replacement (N=3)

COUNT PORTION



Design change 22 92%

Others 1 4%

TOTAL 24 100%

Gear box

Others

TOTAL

1

4

15

TOTAL

Casing

Shaft

Impellert

Bearing

PORTION

PORTION

PORTIONCOUNT

COUNT

COUNT


A. Repaired section or part (N=5) B.Deterioration mode (N=5) C.Corrective measure (N=4)


Casing 1 2% 1 3% 20 61%

Shaft 12 20% 1 3% 2 6%

Impellert 3 5% 2 6% 8 24%Bearing (Except forroutine exchange) 24 41% 2 6% 0 0%

Gear box 6 10% 9 25% 3 9%

Others 13 22% 21 58% 0 0%

TOTAL 59 100% 36 100% 33 100%

(N=4)

COUNT PORTION

<5 15 65%

<10 0 0%

<15 2 9%

<20 0 0%

<25 3 13%

25≦ 3 13%

TOTAL 23 100%

Material change

Design change

Others

TOTAL


Parts exchange

Crack

Deformation

Others

TOTAL

Abrasion

Curvature

Corrosion


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