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.
(c) Deterioration mode and diagnosis method
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.
(c) Deterioration mode and diagnosis method
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
(c) Deterioration mode and diagnosis method
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.
(c) Deterioration mode and diagnosis method
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.
(b) Method and contents of maintenance
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.
(c) Deterioration mode and diagnosis method
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.
(c) Deterioration mode and diagnosis method
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.
7.5 Information concerning maintenance
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.
(c) Deterioration mode and diagnosis method
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.
(b) Methods and contents of maintenance
Time Based Maintenance or Condition Based Maintenance has been carried out, the main content of which is parts exchange.
(c) Deterioration mode and diagnosis method
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.
8.5 Information concerning maintenance
(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.
(c) Deterioration mode and diagnosis method
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.
(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 contents are cleaning.
(c) Deterioration mode and diagnosis method
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.
(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 30% of terminals. The maintenance consists of parts exchange because the piston ring is a consumable part.
(c) Deterioration mode and diagnosis method
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.
(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.
(c) Deterioration mode and diagnosis method
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.
(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 16% of terminals. The main content is cleaning.
(c) Deterioration mode and diagnosis method
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.
(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 16% of terminals. The main content is cleaning, while half of the terminals are using parts exchange.
(c) Deterioration mode and diagnosis method
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
Maintenance has also been carried out at approximately 17% of terminals. The main content is cleaning.
(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.
(b) Method and contents of maintenance
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
Replacement with the samedesigned equipment
Material change
Design change
Others
numbers
Sea water pump
0 1 2 3 4 5
Replacement with the samedesigned equipment
Material change
Design change
Others
numbersSteam boiler
0 1 2 3 4 5
Replacement with the samedesigned equipment
Material change
Design change
Others
numbers
Control system
0 5 10 15
Replacement with the samedesigned equipment
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
Corrosion Abrasion Deformation Others
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
Liquid penetration test
Visual inspection
Dimension
Leak test
Performance test
Others
numbers
B.Maintenance Methord (2)Joint
0 5 10 15 20 25 30
Time Based Maintenance
Condition Based Maintenance
Break Down Maintenance
Life Cycle Cost evaluation
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
Painting Cleaning Partsexchange
Others
numbers
A.Reason for replacement
0
5
10
15
20
Corrosion Abrasion Deformation Others
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
Corrosion Abrasion Deformation Others
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
Replaced with samedesigned equipment
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
Carbon steelStainless steelAluminum alloyTitanium alloy
ConcreteOthers
numbers
A.Material (4)Burmer unit(SCV)
0 5 10 15 20
Carbon steelStainless steelAluminum alloyTitanium alloy
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
Carbon steelStainless steelAluminum alloyTitanium alloy
ConcreteOthers
numbers
A.Material(1)Surface of heat Exchanger tube(SCV)
0 5 10 15 20
Carbon steelStainless steelAluminum alloyTitanium alloy
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
Damage by external stress
Others
numbers
C.Type of deterioration mode (1)Surface of heat Exchanger tube(SCV)
0 5 10 15 20
Corrosion
Crack
Abrasion
Damage by external stress
Others
numbers
C.Type of deterioration mode (2)Tube at bottom LNGHeader(ORV)
0 5 10 15 20
Corrosion
Crack
Abrasion
Damage by external stress
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
Damage by external stress
Others
numbers
CType of deterioration mode (5)Water bath(SCV)
0 5 10 15 20
Corrosion
Crack
Abrasion
Damage by external stress
Others
numbersC.Type of deterioration mode
(6)Blower(SCV)
0 5 10 15 20
Corrosion
Crack
Abrasion
Damage by external stress
Others
numbers
D.Diagnosis method (1)Surface of heat Exchanger tube(ORV)
0 5 10 15 20 25
Liquid penetration test
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
Liquid penetration test
Visual inspectionTube or shell thickness
inspectionLeak test
Performance test
Others
numbers
D.Diagnosis method (3)Extermal shell(Shell and Tube heat exchanger)
0 5 10 15 20
Liquid penetration test
Visual inspectionTube or shell thickness
inspectionLeak test
Performance test
Others
numbers
D.Diagnosis method (4)Burner unit(SCV)
0 5 10 15 20
Liquid penetration test
Visual inspectionTube or shell thickness
inspectionLeak test
Performance test
Others
numbers
D.Diagnosis method (5)Water bath(SCV)
0 5 10 15 20
Liquid penetration test
Visual inspectionTube or shell thickness
inspectionLeak test
Performance test
Others
numbers
D.Diagnosis method (6)Blower(SCV)
0 5 10 15 20
Liquid penetration test
Visual inspectionTube or shell thickness
inspectionLeak test
Performance test
Others
numbers
D.Diagnosis method(1)Surface of heat Exchanger tube(SCV)
0 5 10 15 20
Liquid penetration test
Visual inspectionTube or shell thickness
inspectionLeak test
Performance test
Others
numbers
D.Diagnosis method(1)Surface of heat Exchanger tube(STHE)
0 5 10 15 20
Liquid penetration test
Visual inspectionTube or shell thickness
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
Catheodic protection
Cleaning
Parts exchange
Others
numbers
E.Regular,scheduled and preventivemaintenance
(2)Tube at bottom LNGHeader(ORV)
0 5 10 15 20
Special Coating
Painting
Catheodic protection
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
Catheodic protection
Cleaning
Parts exchange
Others
numbers
E.Regular,scheduled and preventivemaintenance
(4)Burner unit(SCV)
0 5 10 15 20
Special Coating
Painting
Catheodic protection
Cleaning
Parts exchange
Others
numbers
E.Regular,scheduled and preventivemaintenance
(5)Water bath(SCV)
0 5 10 15 20
Special CoatingPainting
Catheodic protectionCleaning
Parts exchangeOthers
numbers
E.Regular,scheduled and preventivemaintenance
(6)Blower(SCV)
0 5 10 15 20
Special Coating
Painting
Catheodic protection
Cleaning
Parts exchange
Others
numbers
E.Regular,scheduled and preventivemaintenance
(1)Surface of heat Exchanger tube(ORV)
0 5 10 15 20
Special Coating
Painting
Catheodic protection
Cleaning
Parts exchange
Others
numbers
A.Reason for replacement
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
Life Cycle Cost evaluation
Others
numbers
B.Maintenance method (1) Shaft
0 5 10 15 20
Time Based Maintenance
Condition Based Maintenance
Break Down Maintenance
Life Cycle Cost evaluation
Others
numbers
B.Maintenance method (2) Impeller
0 5 10 15 20
Time Based Maintenance
Condition Based Maintenance
Break Down Maintenance
Life Cycle Cost evaluation
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
Liquid penetration test
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
Liquid penetration test
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
Liquid penetration test
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
A.Reason for replacement
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
Replaced with samedesigned equipment
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
E.Regular,scheduled andpreventive maintenance
(4)Bearing
0
5
10
15
20
25
30
Cleaning PartsExchange
Others
numbers
E.Regular,scheduled andpreventive maintenance (1)Shaft
0
5
10
15
20
25
Cleaning PartsExchange
Others
numbers
E.Regular,scheduled andpreventive maintenance
(2)Impeller
0
5
10
15
20
25
Cleaning PartsExchange
Others
numbers
A.Repaired section or part
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
Replaced with samedesigned equipment
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
Time Based Maintenance
Condition BasedMaintenance
Break Down Maintenance
Life Cycle Cost evaluation
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
Time Based Maintenance
Condition BasedMaintenance
Break Down Maintenance
Life Cycle Cost evaluation
Others
numbers
B.Maintenance method(4)Piston rod
0 5 10 15 20 25
Time Based Maintenance
Condition BasedMaintenance
Break Down Maintenance
Life Cycle Cost evaluation
Others
numbers
B.Maintenance method(7)Snubber tank
0 5 10 15 20
Time Based Maintenance
Condition BasedMaintenance
Break Down Maintenance
Life Cycle Cost evaluation
Others
numbers
B.Maintenance method(8)Cylinder support
0 5 10 15 20 25
Time Based Maintenance
Condition BasedMaintenance
Break Down Maintenance
Life Cycle Cost evaluation
Others
numbers
B.Maintenance method(5)Connecting rod
0 5 10 15 20 25
Time Based Maintenance
Condition BasedMaintenance
Break Down Maintenance
Life Cycle Cost evaluation
Others
numbers
B.Maintenance method(6)Cylinder liner
0 5 10 15 20 25
Time Based Maintenance
Condition BasedMaintenance
Break Down Maintenance
Life Cycle Cost evaluation
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
Liquid penetration test
Visual inspection
Size inspection
Wall thickness inspection
Others
numbers
D.Diagnosis method (2)Piston
0 5 10 15 20
Liquid penetration test
Visual inspection
Size inspection
Wall thickness inspection
Others
numbers
D.Diagnosis method (3)Piston ring
0 5 10 15 20
Liquid penetration test
Visual inspection
Size inspection
Wall thickness inspection
Others
numbers
D.Diagnosis method (4)Piston rod
0 5 10 15 20 25
Liquid penetration test
Visual inspection
Size inspection
Wall thickness inspection
Others
numbers
D.Diagnosis method (5)Connecting rod
0 5 10 15 20
Liquid penetration test
Visual inspection
Size inspection
Wall thickness inspection
Others
numbers
D.Diagnosis method (6)Cylinder liner
0 5 10 15 20 25
Liquid penetration test
Visual inspection
Size inspection
Wall thickness inspection
Others
numbers
D.Diagnosis method (7)Snubber tank
0 5 10 15 20
Liquid penetration test
Visual inspection
Size inspection
Wall thickness inspection
Others
numbers
D.Diagnosis method (8)Cylinder support
0 5 10 15 20
Liquid penetration test
Visual inspection
Size inspection
Wall thickness inspection
Others
numbers
E.Regular, scheduled and preventive E.Regular, scheduled and preventiv E.Regular, scheduled and
A.Reason for replacement
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
Painting Cleaning Partsexchange
Others
num
bers
E.Regular, scheduled andpreventive maintenance
(5)Connecting rod
0
5
10
15
20
PaintingCleaning Partsexchange
Others
num
bers
E.Regular, scheduled andpreventive maintenance
(6)Cylinder liner
0
5
10
15
20
PaintingCleaning Partsexchange
Others
num
bers
E.Regular, scheduled and preventivemaintenance
(1)Crank shaft
0
5
10
15
20
25
Painting Cleaning Partsexchange
Others
num
bers
E.Regular, scheduled and preventivemaintenance
(2)Piston
0
5
10
15
20
25
Painting Cleaning Partsexchange
Others
num
bers
E.Regular, scheduled andpreventive maintenance
(3)Piston ring
0
5
10
15
20
25
PaintingCleaning Partsexchange
Others
num
bers
E.Regular, scheduled and preventivemaintenance
(7)Snubber tank
0
5
10
15
20
Painting Cleaning Partsexchange
Others
num
bers
E.Regular, scheduled andpreventive maintenance
(8)Cylinder support
0
5
10
15
20
PaintingCleaning Partsexchange
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
A.Repaired section or part
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)
COUNT PORTION COUNT PORTION COUNT PORTION
~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)
COUNT PORTION COUNT PORTION COUNT PORTION
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)
COUNT PORTION COUNT PORTION COUNT PORTION
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
Table 1 (List of applicable unit)
■Capacity(t/h) (N=4) ■Date of installation (N=5) ■Operating hours (N=2)
COUNT PORTION COUNT PORTION COUNT PORTION
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)
E. Regular, scheduled and preventive maintenance
Painting Cleaning Partsexchange
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)
COUNT PORTION COUNT PORTION COUNT PORTION
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%
D. Type of replacement (N=3)
COUNT PORTION
Replaced with samedesigned equipment 8 53%
Material change 0 0%
Design change 7 47%
Others 0 0%
TOTAL 15 100%
Table4 (List of record of repair work)
A.Repaired section or part (N=3) B.Deterioration mode (N=4) C.Corrective measure (N=4)
COUNT PORTION COUNT PORTION COUNT PORTION
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
Replaced with same designedequipmentWelding repair
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
Table 1 (List of applicable unit)
■Capacity(t/h) (N=5) ■Date of installation (N=5) ■Operating hours (N=2)
COUNT PORTION COUNT PORTION COUNT PORTION
~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%
■Manufacturer (N=5) ■Replacement (N=3)
COUNT PORTION COUNT PORTION
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%
Table2 (List of important section or part in maintenance)
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)
B. Maintenance method
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)
E. Regular, scheduled and preventive maintenance
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)
COUNT PORTION COUNT PORTION COUNT PORTION
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%
D. Type of replacement (N=3)
COUNT PORTION
Replaced with samedesigned equipment 8 47%
Material change 7 41%
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
Table4 (List of record of repair work)
A.Repaired section or part (N=3) B.Deterioration mode (N=3) C.Corrective measure (N=3)
COUNT PORTION COUNT PORTION COUNT PORTION
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
Replaced with same designedequipmentWelding repair
Material change
Design change
Others
TOTAL
Curvature
Corrosion
Crack
Deformation
Abrasion
D.Years of operation beforedeterioration
4.Cycle compressor and driver
Table 1 (List of applicable unit)
■Capacity(t/h) (N=4) ■Date of installation (N=3) ■Operating hours (N=3)
COUNT PORTION COUNT PORTION COUNT PORTION
~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%
■Manufacturer (N=5) ■Replacement (N=1)
COUNT PORTION COUNT PORTION
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%
Table2 (List of important section or part in maintenance)
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)
B. Maintenance method
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)
E. Regular, scheduled and preventive maintenance
Painting Cleaning Partsexchange
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)
COUNT PORTION COUNT PORTION COUNT PORTION
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
Replaced with samedesigned equipment 0 0%
Material change 1 4%
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
Table4 (List of record of repair work)
A. Repaired section or part (N=5) B.Deterioration mode (N=5) C.Corrective measure (N=4)
COUNT PORTION COUNT PORTION COUNT PORTION
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
Replaced with same designedequipmentWelding repair
Parts exchange
Crack
Deformation
Others
TOTAL
Abrasion
Curvature
Corrosion
D.Years of operation beforedeterioration