✦ 智能摘要
This Chapter provides guidance on assessing the continued usability of pressure vessels based on fundamental technical analysis (FSF). It includes methods for determining required thickness, evaluating wear and damage, as well as alternative methods for thickness wear evaluation. This Chapter also addresses the use of minimum design documentation to check the integrity of pressure vessels.
适用范围
Pressure vessel users and related technical experts
要点
- Determining the required thickness based on pressure, mechanics, and structure
- Evaluating wear exceeding permissible limits
- Assessing damage from corrosion, fire, dents, and perforations
- Using minimum design documentation to check the integrity of pressure vessels
- Maintaining complete records for pressure vessels and relief devices
🌐 本文件的社会影响
- Ensuring safety in the continued use of pressure vessels
- Providing detailed guidance for technical assessment
- Supporting the maintenance of complete records for effective tracking and management
❓ 常见问题
How to determine the required thickness for a pressure vessel?
The required thickness must be based on considerations of pressure, mechanics, and structure using appropriate design formulas and allowable stresses according to standards.
What alternative methods can be used to evaluate thickness wear?
As an alternative to the evaluations in Points 15.4.2 and 15.4.3, parts with thickness below the required thickness may be evaluated using the ASME Code Section VIII, Division 2, Appendix 4 or API 579-1/ASME FFS Appendix 2D analytical design method.
What records need to be kept for pressure vessels and relief devices?
Records should include full information about pressure vessels and relief devices, including nameplates with maximum allowable working pressure and temperature.
全文
CIRCULAR
Issuing National Technical Regulations
concerning risk-based verification for pressure vessels in oil refineries, natural gas processing plants, and nitrogenous fertilizer plants
oil, gas processing plant, and ammonia plant
___________
Pursuant to Decree No. 98/2017/NĐ-CP dated August 18, 2017, stipulating the functions, tasks, powers, and organizational structure of the Ministry of Industry and Trade;
Pursuant to the Law on Technical Standards and Regulations dated June 29, 2006;
Pursuant to the Law on Product Quality and Commodities dated November 21, 2007;
Pursuant to the Labor Safety and Health Law dated June 25, 2015;
Pursuant to Decree No. 127/2007/NĐ-CP dated August 1, 2007, detailing and guiding the implementation of certain provisions of the Law and Technical Regulations, and Decree No. 78/2018/NĐ-CP dated May 16, 2018, amending and supplementing certain provisions of Decree No. 127/2007/NĐ-CP dated August 1, 2007, detailing and guiding the implementation of the Law on Technical Standards and Regulations;
Pursuant to Decree No. 132/2008/NĐ-CP dated December 31, 2008, detailing and guiding the implementation of certain provisions of the Law on Product Quality, and Decree No. 74/2018/NĐ-CP dated 2018, amending and supplementing certain provisions of Decree No. 132/2008/NĐ-CP dated December 31, 2008, detailing and guiding the implementation of certain provisions of the Law on Product Quality;
Pursuant to Decree No. 39/2016/NĐ-CP of 2016, detailing and guiding the implementation of certain provisions of the Labor Safety and Health Law;
At the proposal of the Director of the Department of Safety Technology and Industrial Environment;
The Minister of Industry and Trade promulgates this Circular on the National Technical Regulation on risk-based verification for pressure vessels in oil refineries, natural gas processing plants, and nitrogenous fertilizer plants.
Article 1. Attached to this Circular is the National Technical Regulation on risk-based verification for pressure vessels in oil refineries, natural gas processing plants, and nitrogenous fertilizer plants.
Code: QCVN 13:2021/BCT
Article 2. Effective Date
This Circular and the National Technical Regulation on risk-based verification for pressure vessels in oil refineries, natural gas processing plants, and nitrogenous fertilizer plants shall take effect from June 1, 2022.
Article 3. Implementation Organization
The Heads of the Office of the Ministry, the Director of the Department of Industrial Safety and Environmental Technology, the Heads of the Science and Technology Departments, the Directors of Provincial Departments of Industry and Trade under the Central Government, the Heads of relevant agencies, organizations, and individuals are responsible for implementing this Circular.
QCVN 13:2021/BCT
NATIONAL TECHNICAL REGULATION
ON RISK-BASED VERIFICATION FOR PRESSURE VESSELS IN OIL REFINERIES, NATURAL GAS PROCESSING PLANTS, AND NITROGENOUS FERTILIZER PLANTS
OIL REFINERY PLANT, GAS PROCESSING PLANT AND AMMONIA PLANT
National Technical Regulation on Verification on the Basis of Risk-Based Inspection for Pressure Vessels in Oil Refineries, Natural Gas Processing Plants, and Nitrogenous Fertilizer Plants
Foreword
QCVN 13:2021/BCT was drafted by the Drafting Team of the National Technical Regulation on risk-based verification for pressure vessels in oil refineries, natural gas processing plants, and nitrogenous fertilizer plants, reviewed by the Department of Industrial Safety and Environmental Technology, examined by the Ministry of Science and Technology, and promulgated by the Minister of Industry and Trade pursuant to Circular No. 13/2021/TT-BCT dated October 27, 2021.
AMENDMENT 1:2025 QCVN 07:2023/BXD
ON RISK-BASED VERIFICATION FOR PRESSURE VESSELS IN OIL REFINERIES, NATURAL GAS PROCESSING PLANTS, AND NITROGENOUS FERTILIZER PLANTS
National Technical Regulation on Verification on the Basis of Risk-Based Inspection for Pressure Vessels in Oil Refineries, Natural Gas Processing Plants, and Nitrogenous Fertilizer Plants
This technical regulation sets out technical requirements, testing methods, sampling procedures; management requirements; responsibilities of organizations and individuals producing, trading, and importing cigarettes.
Thông tư này quy định chi tiết khoản 4 Điều 38 Luật Thủy sản số 18/2017/QH14 đã được sửa đổi, bổ sung tại điểm c khoản 21 Điều 14 Luật số 146/2025/QH15.
1.1. This regulation applies to risk-based verification for pressure vessels constructed and classified according to TCVN 8366:2010 used in oil refineries, natural gas processing plants, and nitrogenous fertilizer plants using natural gas or associated gas as raw materials (nitrogenous fertilizer plants).
1.2. This regulation does not apply to:
- Pressure vessels listed in Appendix A of the API 510 Standard.
- Pressure vessels that are part of transportation equipment.
Thông tư này áp dụng đối với tổ chức, cá nhân có liên quan đến hoạt động kinh doanh đối tượng thủy sản nuôi chủ lực trên lãnh thổ Việt Nam.
This regulation applies to organizations and individuals involved in the installation, use, repair, maintenance, inspection, testing, and verification of pressure vessels as specified in Point 1.1 of this regulation.
In this technical regulation, the following terms are understood as follows:
In this regulation, the following terms are understood as follows:
3.1. Inspection Location (CML)
An area designated on the pressure vessel where external periodic inspections are conducted to directly assess the condition of the pressure vessel. CML may consist of one or more inspection points and utilize various non-destructive testing techniques to achieve the highest probability of detection.
3.2. Risk
Risk is the combination of the likelihood of certain events occurring within a period of interest and the negative consequences related to specific unwanted events.
3.3. Risk-Based Inspection (RBI)
Risk-based inspection involves conducting inspections based on a risk management and assessment process that considers both the likelihood and consequences of equipment failure, focusing on plans to inspect the loss of containment capability of pressure vessels in technological systems due to material degradation. These risks are primarily managed through equipment inspection activities.
3.4. Risk-Based Verification
Risk-based verification involves performing occupational safety and health technical verification taking into account the results of risk-based inspections.
3.5. External Inspection
External inspection is an inspection performed from outside the pressure vessel to determine conditions affecting the integrity of the pressure vessel or conditions harmful to the supporting structures. External inspection can be carried out while the vessel is in operation or shut down.
3.6. Internal Inspection
Internal inspection is an inspection performed from inside the pressure vessel to identify defects that cannot be detected by regular monitoring of external CMLs or during operational inspection methods.
3.7. Operational Inspection
Operational inspection is an inspection performed from outside the operating pressure vessel using non-destructive testing methods to determine if the pressure vessel is suitable for continued use.
3.8. Pressure Vessel Engineer
A pressure vessel engineer is the engineer managing the pressure vessel at the using facility, responsible to the facility owner for tasks related to reviewing design, technical evaluation, analysis, or assessment of pressure vessels and relief devices as prescribed in the API 510 inspection standard.
3.9. Inspector
The inspector is the inspector of the pressure vessel using facility or the contractor's inspector accepted by the facility, trained and competent to perform risk-based inspections. The inspector must have a certified qualification as specified in Appendix B of API 510.
3.10. Non-Destructive Testing (NDT)
NDT is the use of physical methods to inspect and detect defects inside or on the surface of materials without damaging the future usability of the inspected object.
3.11. NDT Personnel
NDT personnel are individuals performing NDT within the scope of work, NDT procedures, and technical requirements of the pressure vessel using facility.
NDT personnel must be trained and hold appropriate NDT certification.
3.12. Inspector
An inspector is a technical occupational safety and health inspector conducting risk-based inspections, holding a certificate issued by the Ministry of Industry and Trade suitable for the inspection object, and having a certificate as specified in Appendix B of API 510.
3.13. FFS (Fitness For Service): Suitability Assessment for Continued Use.
3.14. CUI (Corrosion Under Insulation): Inspection of Corrosion Under Insulation.
3.15. IOW (Integrity Operating Windows): Integrity Operating Limits.
3.16. MOC (Management of Change): Change Management.
1. Requirements for maximum tar and nicotine content in smoke from one cigarette
4. Referenced Standards
- TCVN 8366:2010 - Pressure Vessel - Design and Manufacturing Requirements.
- API 510:2014 - Pressure Vessel Inspection Code: In-service Inspection, Rating, Repair, and Alteration (Pressure Vessel Inspection Standard: Inspection, Evaluation, Repair, and Modification).
- API 572:2016 - Inspection Practices for Pressure Vessels (Inspection Practice Standard for Pressure Vessels).
- API 579-1/ ASME FFS-1:2016 - Fitness For Service (Suitability Assessment for Continued Use Standard).
- API 580:2016 - Risk-Based Inspection (Risk-Based Inspection Standard).
- API 581:2016 - Risk-Based Inspection Methodology (Risk-Based Inspection Methodology Standard).
- ASME PCC-2-2018 - Repair of Pressure Equipment and Piping (Repair Standard for Pressure Equipment and Piping).
- API 571:2020 - Damage Mechanisms Affecting Fixed Equipment in the Refining Industry (Damage Mechanism Assessment Standard for Fixed Equipment in the Refining Industry).
5. General Requirements
5.1. Requirements for the Using Facility to Conduct RBI Evaluation:
a) The facility has established and implemented a safety management system according to international standards (ISO/ OSHAS/BSI...).
b) The facility has a process for conducting RBI.
c) The facility arranges personnel meeting the standards specified in API 580, Clause 5.4 of this regulation.
d) The facility collects complete data as required by Clause 5.3 of this regulation.
đ) RBI Software
RBI software is software that complies with relevant regulations in API 580, API 581 standards and allows for continuous data updates during operation whenever new safety information becomes available, post-inspection evaluations, equipment testing, or when necessary.
5.2. Main Components of the RBI Program
5.2.1. System for maintaining documentation, staff qualifications, data requirements, and analysis updates.
5.2.2. Written method for determining likelihood.
5.2.3. Written method for determining consequences.
5.2.4. Written method for risk management through inspection and other mitigation activities.
5.3. Typical Data Required for RBI Analysis Must Comply With Regulations At Section 7.2 Of API 580.
5.4. Personnel Requirements for RBI Evaluation
5.4.1. RBI Evaluation Team
Depending on the RBI project, the following specific members are selected for the RBI evaluation team:
a) Team Leader.
b) Inspector.
c) Corrosion Assessor.
d) Technology Specialist.
đ) Risk Analyst.
e) Facility Operation and Maintenance Staff.
g) Facility Leadership Representative.
h) Facility Safety and Environmental Staff.
i) Financial and Business Analysts of the Facility (as needed).
5.4.2. Roles, Responsibilities, Training Requirements, and Qualifications of Team Members Participating in RBI Evaluation
Team members participating in RBI evaluation have roles, responsibilities, training requirements, and qualifications as specified in Sections 15.2 and 15.3 of API 580.
The Team Leader and Risk Analyst must hold an API 580 certificate.
The Corrosion Assessor must hold an API 571 certificate or equivalent.
5.5. The Head of the Pressure Vessel Using Facility Implementing RBI Is Responsible For Ensuring That Facility Personnel Or Those Provided By Contractors Are Trained, Experienced, And Hold Appropriate Certifications. The Requirements For Applying RBI As Specified In This Regulation Must Be Met And Maintained During Implementation.
6. Inspection Plan
6.1. Developing the Inspection Plan
6.1.1. The inspection plan is established from analyzing various data sources. Pressure vessels are evaluated based on current or potential damage mechanisms. NDT methods and scopes must be assessed to ensure that designated techniques can fully identify damage mechanisms, extent, and severity. The inspection plan must be scheduled based on consideration of:
a) Type of damage.
b) Rate of damage development.
c) Equipment tolerance to damage type.
d) Ability of NDT methods to detect damage.
đ) Maximum interval as specified in the standard.
e) Previous inspection range.
g) Recent operational history, including any exceedances of integrity operating limits (IOW).
h) Change management records (MOC) that may affect the inspection plan.
i) Previous RBI assessment (if applicable).
6.1.2. The inspection plan must be reviewed and modified when necessary if changes could impact identified damage mechanisms and rates.
6.2. Minimum contents of the inspection plan
The inspection plan must include necessary inspection contents and schedules to monitor failure mechanisms and ensure the mechanical integrity of equipment (pressure vessels or relief devices).
The inspection plan includes:
a) Necessary types of inspections.
b) Dates for the next inspection for each type of inspection.
c) Inspection techniques and NDT (Non-Destructive Testing).
d) Scope, location of inspections and NDT.
đ) Necessary surface cleaning requirements for inspection.
e) Pressure testing requirements.
g) Any planned repairs.
6.3. Additional contents in the inspection plan
The inspection plan may include other contents to explain the fundamental reasons and implementation of the plan. Specifically:
a) Description of failures that have occurred and are likely to occur on the equipment.
b) Identification of failure locations.
c) Any special access requirements.
7. Risk-Based Inspection (RBI)
7.1. Types of RBI assessments
The types of RBI assessments as specified in Section 5.3 API 580.
7.2. Probability assessment
The probability assessment is based on all forms of incidents expected to affect the pressure vessel. Examples of these failure mechanisms include: Metal loss due to localized or uniform corrosion inside or outside, all forms of cracks, metallurgical, corrosion, or other mechanical damage (such as fatigue, embrittlement, cracking, etc.). Additionally, the effectiveness of actual inspection tools and techniques used to detect failure mechanisms should be evaluated. Other factors to be considered in the probability assessment include:
a) Suitability of the manufacturing material.
b) Design conditions of the pressure vessel, related to operating conditions.
c) Suitability of the design standards used.
d) Effectiveness of corrosion monitoring programs.
đ) Quality of inspection and maintenance quality control programs.
e) Maintaining pressure and structural requirements.
g) Operating status, including past and future predictions.
Equipment incident data is important information for this assessment.
Implementation of the probability assessment according to Section 9 API 580.
7.3. Consequence assessment
Consequences depend on the type and quantity of process fluid in the pressure vessel. The consequence assessment considers potential incidents due to fluid release, size and form of discharge (including explosion, fire, or harmful exposure). The assessment also identifies potential incidents due to fluid release, including: Health impact, environmental impact, pressure vessel damage, and downtime of the pressure vessel.
Implementation of the consequence assessment according to Section 10 API 580.
7.4. Documentation
All RBI assessments must be documented according to Section 16 API 580, clearly identifying all factors contributing to both the probability and consequences of pressure vessel incidents. After completing the RBI assessment, the results are used to establish the pressure vessel inspection plan and further clarify the following:
a) The most appropriate inspection methods, tools, techniques, and NDT.
b) The scope of NDT.
c) Internal, external, and in-service inspection intervals.
d) Post-failure or post-repair/replacement pressure testing requirements.
đ) Preventive and mitigating measures to reduce the probability and consequences of pressure vessel incidents.
7.5. Frequency of RBI assessments
When RBI assessments are used to set pressure vessel inspection intervals, the assessment will be updated after each pressure vessel inspection as determined in Section 14 API 580. RBI assessments will also be updated whenever significant technological or equipment changes affecting the rate or mechanism of failure occur, or at any time an unforeseen incident occurs due to a failure mechanism.
8. Preparation for Inspections
8.1. General Requirements
Precautions must be taken during pressure vessel inspections and maintenance, particularly regarding the hazardous and harmful nature of the working medium of the pressure vessel and safety when working in confined spaces or restricted areas.
8.2. Equipment
All tools, equipment, and personal protective equipment used during work with pressure vessels must meet calibration and testing requirements and be inspected before use.
8.3. Communication
When there is someone inside the pressure vessel, all surrounding workers must be informed that someone is working inside the vessel. Individuals working inside the vessel must be notified if any work will be performed inside or outside the vessel while they are inside.
8.4. Entering the Pressure Vessel
Before entering, the vessel must be isolated from all liquid, gas, vapor, radiation, and electrical sources proactively. The vessel must be drained, purged, cleaned, ventilated, and tested before entry. All safe entry procedures and legal regulations must be followed. All safety procedures and restricted space entry permits must be adhered to before entry. The inspector must ensure that all connecting pipelines that could pose a danger to those inside the vessel during inspection are isolated or plugged with blind flanges.
8.5. Reviewing Records
Before implementing any inspection requirements, the inspector must review the operational history of the pressure vessel. Specifically: Previous inspection results, repairs, current inspection plans, as well as all technical evaluations and similar inspection work. A general overview of the modes and types of pressure equipment failures is reviewed in API 571 and Appendix 2B API 579-1/ASME FFS-1.
9. Inspections Based on Different Failure Mechanisms and Types
9.1. Pressure vessels are susceptible to different types of failures through various mechanisms. Inspection techniques for each potential failure mechanism for each pressure vessel must be part of the inspection plan.
Common failure mechanisms and inspection techniques to identify failure mechanisms are described in API 571.
9.2. The potential for damage in pressure vessels depends on the material, design, manufacture, and operating conditions. Inspectors must be familiar with these conditions and the causes and characteristics of latent defects and failure mechanisms.
9.3. More detailed information about failure mechanisms related to corrosion, cracking, etc., including key factors, types, and typical inspection and monitoring techniques in API 571. Additional recommendations for different failure mechanisms are described in API 572.
9.4. Fatigue crack errors must be evaluated, and appropriate inspection plans must be made for cyclically operated pressure vessels (pressure, temperature). Consider the following issues when applying to cyclically operated pressure vessels:
a) Fatigue design criteria from the original manufacturing standard and preventive measures and any special manufacturing details.
b) Internal and external joint types and pipe connections, circumferential weld peaks, repairs, changes, damages, and the possibility of fatigue cracking due to stress concentration at these locations. Technical analysis may be required to determine high-stress areas for evaluation and inspection planning.
c) Internal or external corrosion susceptibility and stress-corrosion cracking and their impact on the vessel's lifespan.
d) Inspection frequency and suitable NDT methods to detect fatigue cracks and the need to measure the size of welds.
10. Types of inspections and monitoring for pressure vessels
10.1. Types of inspections and monitoring
Types of inspections and monitoring include:
a) Internal inspection.
b) In-service inspection.
c) External inspection.
d) Thickness inspection.
đ) Corrosion inspection under insulation.
e) Operational monitoring.
Inspections will be carried out according to each pressure vessel's inspection plan. Consider implementing inspection intervals/frequency and scope according to Article 14. Corrosion and other damages identified during inspections must clearly specify characteristics, dimensions, and evaluate according to Article 15.
10.2. Internal inspection of pressure vessels
10.2.1. General requirements
Internal inspections are conducted according to the inspection plan. Remote visual inspection techniques may support inspecting internal surfaces.
NDT techniques may be required to identify specific vessel damage or operating conditions and should be specified in the inspection plan when necessary. Section 9.4 API 572 provides additional information on internal pressure vessel inspections and is used when conducting inspections.
10.2.2. Internal equipment in pressure vessels
When vessels are equipped with removable internal equipment, such equipment must be removed, within the necessary scope, to allow inspection of pressure-bearing component surfaces. It is not necessarily required to remove all internal equipment if damage in inaccessible areas does not exceed damage in accessible areas of the vessel.
10.2.3. Linings and deposits inside pressure vessels
Inspectors, after consulting with corrosion evaluators, determine when linings or deposits must be removed to conduct thorough inspections. On-site inspections of selected areas may require complete deposit removal to determine the surface condition of the vessel.
Internal linings must be thoroughly inspected. It is not necessary to remove the lining during internal inspections if the internal lining is in good condition and there is no reason to suspect damage occurring behind the lining. If the lining shows damage, swelling, or cracking, parts of the lining must be removed to determine the condition of the lining and the vessel surface. External NDT techniques can be used to determine damage beneath the lining. Consider implementing lining inspection requirements according to Sections 4.3 and 9.4.7 to 9.4.9 API 572.
10.3. In-service inspection of pressure vessels
10.3.1. In-service inspection may be required in the inspection plan. When in-service inspection of a vessel is specified, appropriate NDT techniques are determined in the inspection plan to detect failure mechanisms and associated defects.
10.3.2. Inspection may include several inspection techniques to assess failure mechanisms related to vessel operation. Techniques used in in-service inspection must meet the ability to identify specific failure mechanisms from the outside and the ability to perform while the vessel is in service. Thickness inspection is usually part of in-service inspection.
There are limitations when applying external NDT techniques to determine internal damage location, issues that may affect these limitations include:
a) Manufacturing materials.
b) Welding materials.
c) Tubes, supports, reinforcing plates.
d) Equipment inside the vessel.
đ) Internal linings or coatings.
e) Access and equipment temperature.
g) Limitations of the selected NDT technique for detecting failure mechanisms.
10.3.3. In-service inspection may be accepted instead of internal inspection for vessels in specific cases defined in point 14.5.2.
10.4. External inspection of pressure vessels
10.4.1. General requirements
10.4.1.1. External inspection to check the outer surface condition of the vessel, insulation system, paint, coating, supporting structure, related structures, leaks, vibration, expansion compensation, and vessel installation on supports. Special attention must be paid to inspecting welds used. Inspection must be conducted when any signs of leakage occur.
10.4.1.2. Vessels must be visually inspected for signs of swelling, denting, and abnormal deformation.
10.4.2. Inspection of buried vessels
Buried vessels must be inspected to determine their outer surface condition. Inspection frequency must be based on the effectiveness of the protective coating system (if present) and information on corrosion rates obtained from one or more of the following methods:
a) During maintenance operations on connecting pipelines with similar materials.
b) From the periodic testing of similar buried corrosion test specimens with similar materials.
c) From representative sections of actual vessels.
d) From a vessel under similar conditions.
When inspecting buried vessels, consideration must be given to the potential for damaging the coating and/or cathodic protection system. Buried vessels containing light hydrocarbons must be risk-assessed to help determine inspection frequency and planning, as well as to protect the cathodic protection system, maintain the coating system, and other mitigation activities. Ultrasonic thickness measurement methods or other suitable non-destructive testing (NDT) methods to determine the condition of the external surface may be performed from inside the vessel to monitor external corrosion. Consideration should be given to implementing the soil corrosion provisions in Section 3.57 API 571 when conducting inspections of buried vessels.
10.5. Thickness Measurement
10.5.1. Thickness measurements are conducted to determine the thickness of pressure vessel components. This data is used to determine the rate of corrosion and remaining life of the vessel.
10.5.2. Expert opinion on corrosion assessment is required when short-term corrosion rates significantly change compared to previously determined rates to identify the cause. Appropriate actions when corrosion rates increase may include additional thickness measurements, ultrasonic testing of suspect areas, technological monitoring, corrosion, and modification of the pressure vessel inspection plan.
10.5.3. The user of the pressure vessel is responsible for ensuring that all individuals involved in thickness measurements are trained and competent according to the procedures applied during the inspection process.
10.6. Inspection of Corrosion Under Insulation (CUI)
10.6.1. Temperature Range Influencing CUI
CUI inspections will be considered for externally insulated vessels and those operating intermittently or at temperatures:
a) From -12°C to 175°C for carbon steel and low alloy steels.
b) From 60°C to 175°C for Austenitic stainless steel.
c) From 138°C to 175°C for Duplex stainless steel.
10.6.2. Locations Prone to CUI on Equipment
For carbon and low alloy steels, CUI typically manifests as localized corrosion. For Austenitic and Duplex stainless steels, CUI often appears as chloride-induced stress-corrosion cracking. When planning CUI inspections, inspectors must consider the most susceptible areas but note that CUI damage locations can be unpredictable. For pressure vessels, the most vulnerable areas include:
a) On stiffening rings and insulation wraps.
b) Pipe connections and manholes.
c) Other penetration points.
d) Damaged insulation with water ingress areas.
đ) Areas with insulation damage.
e) The top and bottom of the vessel.
g) Other areas prone to water condensation.
If CUI damage is detected, the inspector should consider inspecting other areas of the vessel.
10.6.3. Removal of Insulation Jacket
Although the outer jacket may appear in good condition, CUI can still occur beneath it.
CUI inspections may require partial or complete removal of the insulation jacket. If the outer jacket is in good condition and there is no reason to suspect internal damage, it is not necessary to remove the jacket for inspection.
Factors to consider regarding the need to remove the insulation jacket include but are not limited to:
a) Consequences of leaks due to CUI.
b) History of CUI inspections for the vessel or similar equipment.
c) Visual condition of the coating and outer jacket.
d) Evidence of liquid leakage.
đ) Equipment operation interruptions.
e) Condition and age of the underlying paint layer.
g) Insulation jacket's moisture absorption and retention capability.
h) The feasibility of applying specialized NDT techniques effectively without removing the jacket.
Additionally, thickness measurements of the vessel shell in typical CUI problem areas can be performed from inside the vessel during internal inspections.
10.7. Operational Monitoring
Operators must report unusual issues with pressure equipment and safety relief devices, including: vibration, signs of leakage, abnormal noise, insulation degradation, opened safety relief devices, distortion, dents, temperature deviation, rust under insulation, etc.
11. Corrosion Monitoring Locations (CML)
11.1. General Requirements
CMLs are designated locations on pressure vessels where periodic inspections are conducted to monitor the presence and extent of damage. The type and location of CMLs selected must consider the potential for localized corrosion and specific damage mechanisms based on the service fluid as per Article 9 and Section 5.4 API 510. Examples of different types of CMLs include thickness measurement locations, locations for checking stress-corrosion cracking, and high-temperature hydrogen attack inspection locations.
11.2. CML Inspection
11.2.1. Each pressure vessel must be monitored through representative inspections at CMLs to meet requirements for internal or in-service inspections. The corrosion rate, remaining life, and next inspection interval must be calculated. CMLs with the highest corrosion rates and shortest remaining lives will be included in the planned next inspection cycle.
11.2.2. Pressure vessels with high risk if failure occurs, experiencing higher corrosion rates, localized corrosion, and higher failure rates from other structures will have more CMLs and be monitored more frequently. Corrosion rates must be determined from continuous measurements, and the next inspection interval must be set accordingly.
11.2.3. The minimum thickness at CMLs can be determined by ultrasonic measurements or other appropriate methods.
11.2.4. The smallest or average remaining thickness of several measurements taken in the area of the inspection point must be recorded and used to calculate the corrosion rate.
11.2.5. CMLs and inspection points must be documented regularly to facilitate accurate measurements in subsequent inspections to improve the accuracy of metal corrosion status.
11.3. Selection and Location of CMLs
11.3.1. The Decision on the type, quantity, and location of CMLs shall be based on the results of previous inspections, the form of corrosion and anticipated damage, and the potential consequences of loss of containment capacity. CMLs must be distributed appropriately across the tank to provide full coverage for monitoring the main components and connecting pipes.
11.3.1.1. Additional CMLs should be selected for pressure vessels with any of the following characteristics:
a) High likelihood of creating an immediate safety or environmental emergency in case of leakage, unless it is known that the internal corrosion rate is relatively low and uniform.
b) Anticipated or experienced high corrosion rates.
c) High likelihood of localized corrosion.
11.3.1.2. A smaller number of CMLs may be chosen for pressure vessels with any three of the following characteristics:
a) Low likelihood of creating a safety or environmental emergency in case of leakage.
b) Relatively non-corrosive medium.
c) Generally uniform corrosion rate.
11.3.2. The number of CMLs may be reduced or eliminated when the likelihood and consequences of failure are assessed as low, consulting with corrosion assessment experts in such cases.
12. Evaluation Method
12.1. Selection of Inspection Techniques
12.1.1. General Requirements
Potential types of damage that may occur during the inspection process of pressure vessels must be considered when selecting inspection techniques. Consultation with corrosion assessment experts or risk analysts is required to determine the type of damage, NDT techniques, and level of inspection.
12.1.2. Surface Preparation
Surface preparation and evaluation for NDT inspection techniques depend on specific circumstances.
12.2. Wall Thickness Measurement Methods
12.2.1. Wall thickness measurement is necessary to determine the extent of corrosion.
12.2.2. Prioritize using ultrasonic scanning or radiographic deformation techniques when localized corrosion or remaining wall thickness approaches the limit thickness.
12.2.3. Consider the effects of metal temperature on the accuracy of wall thickness measurements and minimize errors.
12 2.4. Consider the impacts affecting the accuracy of measurements during implementation and minimize error occurrence. Factors contributing to reduced accuracy of ultrasonic measurements include:
a) Inappropriate equipment calibration.
b) Surface coating or rust.
c) Excessive surface roughness.
d) Influence of object curvature radius on probe contact.
đ) Subsurface material defects, such as delamination.
e) Temperature effect (above 65°C).
g) Small defect detection screen.
h) Using double reflection for thin materials.
i) NDT personnel experience.
13. Hydrostatic Testing
13.1. Hydrostatic testing is required before initial use, after major changes or repairs, or after periodic inspection due date according to the specified test pressure requirements.
13.2. Hydrostatic testing is conducted on the entire vessel. However, representative parts of the vessel can be tested if they can substitute for the whole vessel.
13.3. Hydrostatic Test Pressure
The minimum hydrostatic test pressure for vessels designed to ASME Code, Section VIII, Division I standards is as follows:
For equipment manufactured prior to 1999:
For equipment manufactured from 1999:
Where:
Pth: Test pressure, MPa.
plv,: Maximum allowable working pressure, MPa.
S1: Allowable stress at test temperature, MPa
S2: Allowable stress at design temperature, MPa.
13.4. Alternative to Hydrostatic Testing
13.4.1. In the absence of major changes or repairs, based on inspection results and RBI evaluation, the certification organization and user facility assess and decide on the necessity of hydrostatic testing.
13.4.2. When NDT is used as an alternative to hydrostatic testing after major changes or repairs or periodic inspection, an FFS assessment must be performed to determine critical flaw sizes for acceptance criteria for the designated NDT technique. Refer to Article 502 ASME PCC-2 regarding NDT as an alternative to pressure testing for repairs and modifications.
14. Inspection Interval/Frequency and Level
14.1. General Requirements
14.1.1. To ensure the integrity of the vessel, all pressure vessels must be inspected, and relief devices must be inspected and tested according to the intervals/frequencies specified herein.
14.1.2. Proper inspection will provide necessary information to confirm that all components or essential parts of the equipment are safe for operation until the next inspection. Shutdown and startup risks, increased corrosion due to exposure of the vessel's surface to air and moisture must be evaluated when developing an internal inspection plan.
14.2. Inspection During Installation and Operational Changes
14.2.1. Installation of Vessels
Pressure vessels must be inspected upon installation. Basic information and initial wall thickness measurements at designated CMLs should be collected.
14.2.2. Operational Changes to Vessels
14 2.2.1. If the operational status of the vessel changes, inspection intervals must be established for the new operational status.
14.2.2.2. In the case of ownership or installation location change, the vessel must be internally and externally inspected before reuse. Additionally, permissible operating conditions and inspection intervals must be set for the new operation.
14.2.2.3. In some cases, re-analysis or review/reconfirmation of the user facility's technical requirements may be required.
14.3. Establishing Inspection Intervals Based on RBI
14.3.1. RBI evaluation can be used to establish appropriate inspection intervals for internal inspections, operational condition inspections, and external inspections, as well as inspection and testing intervals for relief devices.
14.3.2. When the RBI interval for internal inspections or operational condition inspections exceeds ten years, the RBI evaluation must be reviewed and approved by pressure vessel engineers and inspectors within a period not exceeding ten years or shorter if there are technological, equipment, or consequence changes.
14.3.3. The RBI assessment is used to extend the internal inspection or operational testing period. At that time, the assessment must include an evaluation of the inspection history and the failure potential of the pressure vessel relief device.
14.3.4. The RBI assessments must comply with API 580.
14.4. External Inspection
14.4.1. Each above-ground tank must undergo an external visual inspection at intervals not exceeding five years or an internal inspection/testing under operating conditions as required.
14.4.2. The external inspection interval for non-continuous operation tanks is similar to that for continuous operation tanks because the external environment does not change for non-continuous operation tanks.
14.5. Internal Inspection, Operational Testing, and Wall Thickness Measurement
14.5.1. Inspection Intervals
14.5.1.1. The interval between internal inspections or operational testing and wall thickness measurement shall not exceed half the remaining life of the tank or ten years, whichever is less.
Whenever the remaining life is less than four years, the inspection interval may be the entire remaining life up to a maximum of two years. The interval is established by the inspector or pressure vessel engineer according to the owner/user facility's quality management system.
14.5.1.2. For non-continuous operation pressure vessels, this interval is based on the actual number of years of operation of the vessel provided that when not in operation, the pressure vessel:
a) Is isolated from process liquid.
b) Does not come into contact with corrosive internal environments.
Non-continuous operation vessels that are not adequately protected from corrosive environments may increase internal corrosion while not in operation. The rate of corrosion must be carefully considered before establishing internal inspection or operational testing intervals.
14.5.1.3. Another method to establish necessary inspection intervals is to calculate the maximum allowable working pressure of each component of the vessel as specified in Point 15.3. Unless an RBI assessment is performed, the maximum inspection interval using this method is also ten years.
14.5.2. Operational Testing in Lieu of Internal Inspection
14.5.2.1. Operational testing can replace internal inspection in the following cases:
a) When the size or geometric shape of the vessel does not allow access to the interior for inspection.
b) For vessels that can be accessed internally for inspection but meet all of the following conditions simultaneously:
- The uniform corrosion rate of the vessel measured and calculated is less than 0.125 mm/year.
- The remaining life of the vessel exceeds ten years.
- The corrosivity characteristics of the contents inside the vessel have been monitored and established over a minimum of five years under similar operating conditions as specified in Section 3.1.67 API 510.
- External inspection has not revealed any abnormal signs.
- The operating temperature of the shell does not exceed the material creep limit shown in Table 1.
Table 1. Material Creep Limits
Type of material Material Creep Limits
Carbon Steel (UTS ≤ 414 MPa)
343°C (UTS > 414 MPa)
Carbon Steel (UTS ≤ 414 MPa)
371°C Carbon Steel - Graphitized
C-1/2Mo Alloy Steel Carbon Steel - Graphitized
399°C 1-1/4Cr-1/2Mo Alloy Steel - Normalized and Tempered
427°C 1-1/4Cr-1/2Mo Alloy Steel - Annealed
2-1/4Cr-1Mo Alloy Steel - Normalized and Tempered 1-1/4Cr-1/2Mo Alloy Steel - Annealed
2-1/4Cr-1Mo Alloy Steel - Annealed 427*0
2-1/4Cr-1Mo Alloy Steel - Quenched and Tempered 1-1/4Cr-1/2Mo Alloy Steel - Annealed
2-1/4Cr-1Mo Alloy Steel - V 1-1/4Cr-1/2Mo Alloy Steel - Annealed
441°C 3Cr-1Mo-V Alloy Steel
5Cr-1/2Mo Alloy Steel 3Cr-1Mo-V Alloy Steel
7Cr-1/2Mo Alloy Steel 1-1/4Cr-1/2Mo Alloy Steel - Annealed
9Cr-1Mo Alloy Steel 1-1/4Cr-1/2Mo Alloy Steel - Annealed
9Cr-1Mo-V Alloy Steel 1-1/4Cr-1/2Mo Alloy Steel - Annealed
454°C 12Cr Alloy Steel
482°C AISI Grades 304 & 304H Stainless Steel
510°C AISI Grades 316 & 316H Stainless Steel
538°C AISI Grade 321 Stainless Steel
538°C AISI Grade 321H Stainless Steel
AISI Grade 347 Stainless Steel AISI Grade 321 Stainless Steel
AISI Grade 347H Stainless Steel AISI Grade 321 Stainless Steel
Alloy 800 AISI Grade 321 Stainless Steel
565°C Alloy 800H
Alloy 800HT Alloy 800H
HK-40 Alloy Alloy 800H
649°C - The vessel operates with internal contents that do not cause failure mechanisms such as cracking or hydrogen damage.
- The interior of the vessel does not have partially adhered linings, such as strip or plate linings.
14.5.2.2. If the requirements of paragraph b of Article 14.5.2.1 are not met, the next inspection will be an internal inspection. Operational testing may be conducted if the RBI assessment determines that the risk associated with the vessel is low enough to be acceptable and the non-destructive external testing method is sufficiently reliable to assess and determine the failure mechanisms of the vessel. The assessment must consider the technological process, past, present, and future contents inside the vessel.
14.5.2.3. An operational inspection replacing an internal inspection can be considered for implementation by the inspector based on the results of an internal inspection of another similar vessel under the same operating conditions.
14.5.2.4. The following may be applied when comparing pressure vessels with similar operations.
a) When a pressure vessel has undergone an internal inspection, the results of that inspection can be used to determine whether operational testing can replace internal inspection on another pressure vessel operating under the same conditions.
b) In the case where two or more pressure vessels are installed in series without any corrosive contaminants being introduced at an intermediate point or having the potential to affect the integrity of the vessels, and the operating conditions are identical and full historical corrosion data is available, inspecting one vessel (preferably the worst-case scenario) can represent the entire group of vessels.
c) Risk assessment or RBI analysis may be useful when considering the degree of applicability of similar operating conditions when determining the requirements for internal inspection and operational testing based on the comparison of one pressure vessel with another and the number of pressure vessels inspected within a group.
c) Risk assessment or RBI analysis may be useful when considering the extent of application of similar operating conditions when determining the requirements for internal inspection and inspection during operation based on comparing one pressure vessel with another and the number of pressure vessels inspected within a group.
14.5.2.5. When the operational condition inspection is carried out, the type and scope of NDT must be specified in the approved plan. This may include ultrasonic thickness measurements, radiographic testing, or other suitable NDT methods to measure metal thickness or assess the integrity of pressure-bearing components.
14.5.2.6. In certain special cases, where pressure vessels within a process line cannot be stopped or inside vessels containing catalysts that require complete replacement of the catalyst upon opening, internal inspections may be replaced with external NDT inspections. However, the development of the NDT inspection plan should consult the technology rights provider, catalyst supplier, or pressure vessel supplier. Internal inspections must be conducted when the vessel can be opened or at the time of complete catalyst replacement. Organizations and individuals managing and using the equipment must maintain and be responsible for safe working conditions for machines and equipment.
14.5.3. Multi-zone vessels
For large vessels with two or more zones having different rates of corrosion, each zone may be treated independently when determining inspection intervals or replacing internal inspections with operational condition inspections. Each zone will be inspected based on its own interval.
14.6. Pressure relief devices
14.6.1. Pressure relief devices must be tested and inspected at sufficiently frequent intervals to verify that the devices operate reliably under specific operating conditions. The inspection intervals for all pressure relief devices are determined by the inspector, pressure vessel engineer, or qualified individual according to the owner/user facility's quality management system.
14.6.2. Unless an RBI assessment indicates that longer intervals are acceptable, testing and inspection intervals for pressure relief devices in typical process fluids shall not exceed:
a) 5 years for typical process fluids.
b) 10 years for clean (non-mixed) and non-corrosive fluids.
14.6.3. Upon discovery of significant jamming or blockage of pressure relief devices, the inspection and testing intervals will be reassessed to determine if they should be shortened. The assessment must identify the cause of the failure or reason for the device's improper operation.
15. Inspection data evaluation, analysis, and record keeping
15.1. Determining corrosion rate
15.1.1. Existing pressure vessels
15.1.1.1. The corrosion rate is determined by the difference between two thickness readings divided by the time interval between the two measurements. Determining the corrosion rate may include thickness data obtained from more than two measurements. Short-term corrosion rates are typically determined by the two most recent thickness readings while long-term corrosion rates use the most recent reading and the initial reading at the start of the equipment's life cycle.
These different rates help to distinguish recent corrosion mechanisms from those that have been active over a longer period.
Long-term corrosion rate (LT) is calculated from the following formula:
Short-term corrosion rate (ST) is calculated from the following formula:
Where:
t1 = Initial thickness at the same location as t3. It can be measured at this CML or at the beginning of the new corrosion environment, mm.
t2 = Previous thickness measurement taken during the previous inspection. It is at the same location as t3, mm.
t3 = Actual thickness of the CML measured in the most recent inspection, mm.
15.1.1.2. When evaluating the corrosion rate as part of the data evaluation, the inspector, with the advice of a corrosion analyst, must select the corrosion rate that best reflects the current condition. The following issues must be considered when using the corrosion rate in the corrosion area to calculate remaining life and next inspection interval:
a) Whether the corrosion damage mechanism is uniform or localized.
b) Areas affected by liquid, erosive liquid, or corrosion-erosion conditions.
c) Estimated time of corrosion onset (if not from initial operation) as a basis for measuring wall loss and appropriate time to determine the corrosion rate.
d) Potential points of process changes that could cause corrosion.
đ) The effect of deposit formation either protecting parts from corrosion or losing that protection.
e) The potential for increased corrosion rates in stagnant areas.
g) Continued operation within the integrity operating window.
15.1.2. Newly installed or changed operation pressure vessels
For newly installed pressure vessels or vessels with changed operating conditions, one of the following methods will be used to determine the possible corrosion rate of the vessel. Remaining life and inspection interval can be estimated from this rate.
15.1.2.1. The corrosion rate can be calculated from data collected by the owner or user facility on similar operating conditions vessels. If such data is not available, consider alternative options.
15.1.2.2. The corrosion rate can be estimated by a corrosion analyst.
15.1.2.3. The corrosion rate can be estimated from published data on similar operating condition vessels.
15.1.2.4. If the corrosion rate cannot be determined by any of the above methods, an operational condition determination must be performed after approximately 3 to 6 months of operation using suitable corrosion monitoring devices or actual thickness measurement of the vessel. Subsequent determinations must be made at appropriate intervals until the corrosion rate is determined.
15.2. Calculating remaining life
15.2.1. The remaining life of the vessel (in years) based on the corrosion rate is calculated using the following formula:
Where:
tactual = Actual thickness of a CML (mm) measured in the most recent inspection.
trequired = Required thickness at the same CML or component (mm) when tactual was measured. It is calculated by design formulas and does not include additional thickness for corrosion or manufacturer tolerance.
15.2.2. A statistical analysis may be used for corrosion rates and remaining life calculations for pressure vessel components.
This statistical method may be applied to evaluate internal inspection testing (Clause b Point 14.5.2.1) or to determine the interval between internal inspections. It is important to ensure that the statistical processing of data reflects the actual condition of the component, particularly those subject to localized corrosion. Statistical analysis shall not be applied to vessels with significant random localized corrosion. The analytical method must be documented in writing.
15.3. Determining the maximum allowable working pressure
15.3.1 The maximum allowable working pressure for continued use of a pressure vessel must be based on calculations determined using the latest version of the ASME standard or the manufacturing standard of the vessel. The resulting maximum allowable working pressure from these calculations must not exceed the initial maximum allowable working pressure unless a re-evaluation is performed according to Section 8.2 API 510.
15.3.2 Calculations can only be performed if the necessary details comply with the requirements of the applicable standard: Heads, shells, and reinforcing pipe connections; material technical requirements; allowable stress; weld strength factor; acceptance criteria for testing; and cyclic operation requirements.
15.3.3 In corrosive media, the shell thickness used in these calculations must be the actual thickness determined by inspection minus twice the estimated pre-inspection corrosion loss before the next inspection:
Where:
Crate = dominant corrosion rate, mm/year.
Ibên trong = internal inspection or operational test interval, years.
tthực tế = actual thickness of the CML, measured in (mm), from the most recent inspection.
15.3.4 Multi-point measurements must be conducted when determining the actual thickness of inspected parts larger or smaller than the reported thickness in the material test report or manufacturer's data report, especially if the part was manufactured by casting.
15.4. Fitness-for-service analysis for corroded areas
15.4.1 General Requirements
The actual thickness and maximum corrosion rate of any vessel component may be adjusted at any of the following inspections.
15.4.2 Evaluation of Localized Corroded Areas
15.4.2.1 For significantly sized corroded areas, the wall thickness may be averaged over a length not exceeding the following values:
a) For vessels with an inside diameter of less than or equal to 1500 mm, half the vessel diameter or 500 mm, whichever is smaller.
b) For vessels with an inside diameter greater than 1500 mm, one-third the vessel diameter or 1000 mm, whichever is smaller.
15.4.2.2 Along the defined length, thickness measurements must be taken at uniform intervals. For significantly sized areas, multiple lines within the corroded area may need to be evaluated to determine which length has the lowest average thickness. The following criteria must be met to use the average thickness:
a) Relatively uniform metal loss without grooves (i.e., insignificant localized stress concentrations).
b) Equipment not operating in the fatigue limit.
c) Components not operating cyclically.
d) The data set must include a minimum of 15 thickness measurement points.
đ) The number of measurement points must include the average thickness.
e) The lowest individual reading must not be less than 50% of the requirement.
15.4.2.3 If circumferential stress dominates (characteristic of most vessels), thickness measurements are made longitudinally. If longitudinal stress dominates (due to wind loads or other factors), thickness measurements are made circumferentially (arc).
15.4.2.4 When averaging near discontinuous structures (e.g., pipe connections, conical transition sections, flange connections), the average thickness limit must be considered separately from the reinforced area (or another region with high local stress) and the area outside or adjacent to the reinforced area (or another region with high local stress).
a) When averaging near a pipe connection, the specified length must not extend to the reinforcement area as defined in the manufacturing standard. Any additional reinforcement included in the pipe connection design must be considered.
b) Technical considerations for averaging in the reinforced area for structural discontinuities are provided in API 573-1/ASME FFS-1, Part 4.
15.4.2.5 When performing remaining life calculations as per Point 15.2, the lowest average thickness of any length within the corroded area replaces tthực tế.
15.4.3 Evaluation of Pitting Corrosion
During inspections, scattered pitting corrosion locations may be disregarded if they meet all the requirements specified in Section 7.4.3 API 510.
15.4.4 Alternative Assessment Method for Thickness Loss
15.4.4.1 As an alternative to the assessments in Points 15.4.2 and 15.4.3, components thinner than the required thickness may be assessed using the ASME Section VIII, Division 2, Appendix 4 or API 579-1/ASME FFS Appendix 2D analysis method.
15.4.4.2 When using ASME Section VIII, Division 2, Appendix 4, the original design stress value used in the pressure vessel must be replaced with the maximum allowable stress value (Sm) of Division 2 if the design stress is less than or equal to two-thirds of the minimum yield strength (SMYS) at temperature. If the original design stress exceeds two-thirds of the minimum yield strength at temperature, then two-thirds of the minimum yield strength at temperature will replace Sm.
15.4.5 Adjustment of Weld Strength Factor
When the surface of the vessel is corroded far from the weld and the weld strength factor is less than 1, an independent calculation using an appropriate weld strength factor (usually 1) may be performed. For this calculation, the surface around a weld includes 25 mm on each side of the weld or twice the required thickness on each side of the weld, whichever is greater.
15.4.6 Corroded Areas in Vessel Ends
15.4.6.1. The necessary thickness at the areas subject to corrosion of ellipsoidal and spherical heads may be determined as follows:
a) In the curved portion of the cylindrical head, use the appropriate head formula in the manufacturing standard.
b) At the middle portion of the head, use the hemispherical head formula in the manufacturing standard. The middle portion of the head is defined as the center of the head with a diameter equal to 80% of the body diameter.
15.4.6.2. For conical heads, the radius used in the hemispherical head formula is the cone radius.
15.4.6.3. For ellipsoidal heads, the radius used in the hemispherical head formula must be the equivalent spherical radius K1xD, where D is the body diameter (internal diameter) and K1 is provided in Table 2. In Table 2, h is half the length of the minor axis. For multiple ellipsoidal heads, D/2h - 2.
Table 2. Values of the spherical radius coefficient K1
D/2h K1
3,0 1,36
2,8 1,27
2,6 1,18
2,4 1,08
2,2 0,99
2,0 0,90
1,8 0,81
1,6 0,73
1,4 0,65
1,2 0,57
1,0 0,50
Note: The equivalent spherical radius equals K1D; the axis ratio is D/2h. Interpolation is allowed for intermediate values.
15.5. Assessment of FFS (suitability for continued service)
Components subjected to pressure that have defects which may affect their load-bearing capacity (pressure loads and other applied loads, such as weight, wind, etc., according to API 579-1/ASME FFS-1) must be assessed for continued service. Suitable assessments for continued service, such as those in API 579-1/ASME FFS-1, can be used for this assessment and must be applied to specific observed damage. The following techniques may be used as alternatives to the assessment techniques in point 15.4.
15.5.1. To assess metal loss exceeding permissible corrosion, an FFS assessment may be performed according to API 579-1/ASME FFS-1, Part 4, 5, or 6. This assessment requires the use of additional values due to future corrosion, established based on Part 6 of this standard.
15.5.2. To assess blistering, hydrogen-induced cracking (HIC)/sulfide stress cracking (SSC), and layering damage, the corresponding FFS assessment must be carried out according to Parts 7 and 13 of API 579-1/ASME FFS-1. In some cases, this assessment will require the use of additional corrosion allowance thicknesses, established based on Part 6 of this standard.
15.5.3. To assess weld misalignment and body distortion, the FFS assessment must be conducted according to Part 8 of API 579-1/ASME FFS-1.
15.5.4. To assess crack-like defects, the FFS assessment must be conducted according to Part 9 of API 579-1/ASME FFS-1.
15.5.5. To assess the impact of damage caused by erosion, the FFS assessment must be performed according to Part 10 of API 579-1/ASME FFS-1.
15.5.6. To assess the impact of damage caused by fire, the FFS assessment must be performed according to Part 11 of API 579-1/ASME FFS-1.
15.5.7. To assess damage from dents and gouges on components, the FFS assessment must be performed according to Part 12 of API 579-1/ASME FFS-1.
15.6. Determination of Required Thickness
The required thickness must be based on considerations of pressure, mechanics, and structure using appropriate design formulas and allowable stresses of the standard. For media where failure could result in high consequence, an increase in the required thickness over the calculated minimum thickness must be considered to provide for unforeseen or undetermined loads and undetected metal loss.
15.7. Evaluation of Existing Equipment with Minimal Documentation
For pressure vessels without nameplates and with minimal or no design and fabrication documentation, the following steps may be used to verify operational integrity:
a) Conduct a condition survey of the vessel including a complete dimensional inspection of all necessary components to determine the minimum required thickness and the adequacy of the vessel design.
b) Determine design parameters and prepare drawings.
c) Perform design calculations based on applicable standards. Do not use the current ASME standard allowable stress values (based on a design factor of 3.5) for vessels designed before 1999 and not designed according to ASME Code Case 2290 or 2278. For vessels designed before 1999 and not designed according to ASME Code Case 2290 or 2278, use the pre-1999 ASME standard allowable stress values (based on a design factor of 4.0 or 5.0).
When the initial radiographic examination extent is unknown, use the weld joint efficiency factor specified in Section 7.7 of API 510.
d) Attach a nameplate with the maximum allowable working pressure and temperature, the minimum allowable working temperature, and the date of manufacture.
e) Perform hydrostatic testing according to the requirements of the standard used for design calculations.
15.8. Reporting and Records
15.8.1. The user of the pressure vessel must maintain complete records of the pressure vessel and relief devices. The records must be kept throughout the life of each device and updated regularly with new information related to operation, inspection, and maintenance history of the equipment.
15.8.2. Pressure vessel and relief device records must contain four types of information relevant to mechanical integrity as follows:
a) Design and fabrication information.
b) Inspection history. The RBI record of the pressure vessel must comply with Section 16 of API 580. The records also need to indicate how each inspection recommendation was handled, including reasons why an inspection recommendation was not implemented.
c) Information on repairs, modifications, and re-evaluations:
- Repair and modification forms according to Appendix D of API 510;
- Reports issued with equipment operating with identified deficiencies, temporary repairs, or recommendations for repairs, FFS assessments until repairs can be completed;
- Re-evaluation documentation (including re-evaluation calculations, new design conditions, and tested conditions).
d) FFS evaluation documentation requirements are specified in Section 2.8 of API 579-1/ASME FFS-1.
15.8.3. Operation and maintenance records, such as operating conditions, technological incidents that may affect mechanical integrity, and maintenance damage must be retained and available when requested by inspectors. Refer to Appendix C of API 572 for record form templates.
III. RESPONSIBILITIES OF ORGANIZATIONS AND INDIVIDUALS INSTALLING, USING, REPAIRING, MAINTAINING, INSPECTING, TESTING, AND CERTIFYING PRESSURE VESSELS
16. The periodic inspection period for pressure vessels is specified as follows:
a) External and internal inspection: once every three years.
b) External, internal inspection and pressure testing: once every six years.
For containers holding corrosive media, the inspection period shall be reduced by one-third of the time.
17. In cases where the user entity has implemented RBI in compliance with the relevant provisions, the Inspector shall consider using the RBI inspection results during the pressure vessel inspection process.
18. Organizations and individuals installing, repairing, maintaining, inspecting, testing, consulting, and inspecting pressure vessels must comply with the relevant provisions of this Standard when performing tasks related to RBI.
IV. IMPLEMENTATION
19. The Department of Safety Technology and Environmental Protection is responsible for coordinating with relevant agencies and units to guide and supervise the implementation of this Standard.
Annually, the Department of Safety Technology and Environmental Protection is responsible for inspecting and evaluating the implementation of RBI assessments at user entities conducting RBI assessments.
Based on management requirements, the Department of Safety Technology and Environmental Protection is responsible for recommending the Minister of Industry and Trade to amend and supplement this Standard.
20. Provincial Departments of Industry and Trade under centrally governed cities are responsible for supervising the implementation of the provisions of this Standard within their jurisdiction.
21. In cases where international treaties to which Vietnam is a party have different provisions from those of this Standard, such provisions shall be implemented according to the international treaty./.
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127/2007/NĐ-CP
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98/2017/NĐ-CP
Nghị định số 98/2017/NĐ-CP Quy định chức năng, nhiệm vụ, quyền hạn và cơ cấu tổ chức của Bộ Công Thương
已失效
68/2006/QH11
Nghị quyết số 68/2006/QH11 Về dự toán ngân sách nhà nước năm 2007
生效中
74/2018/NĐ-CP
Nghị định số 74/2018/NĐ-CP Sửa đổi, bổ sung một số điều của Nghị định số 132/2008/NĐ-CP ngày 31 tháng 12 năm 2008 của Chính phủ quy định chi tiết thi hành một số điều Luật chất lượng sản phẩm, hàng hóa
生效中
132/2008/NĐ-CP
Nghị định số 132/2008/NĐ-CP Quy định chi tiết thi hành một số điều của Luật chất lượng sản phẩm, hàng hóa
生效中
39/2016/NĐ-CP
Nghị định số 39/2016/NĐ-CP Quy định chi tiết thi hành một số điều của Luật An toàn, vệ sinh lao động
生效中
05/2007/QH12
Luật Chất lượng sản phẩm, hàng hoá số 05/2007/QH12
生效中
78/2018/NĐ-CP
Nghị định số 78/2018/NĐ-CP Sửa đổi, bổ sung một số đều của Nghị định số 127/2007/NĐ-CP ngày 01 tháng 8 năm 2007 của Chính phủ quy định chi tiết thi hành một số điều Luật tiêu chuẩn và quy chuẩn kỹ thuật.
生效中
13/2021/TT-BCT
Circular 13/2021/TT-BCT on inspection of pressure vessels at oil refining plants, gas processing plants, and fertilizer plants
In effect
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