1. The objectives of the project were:
2. The scope of the intervention was limited to in-service piping systems within the site boundary.
3. The study focussed primarily on in-service inspection and maintenance issues . But other aspects such as design to code (e.g. ASME B31.3 2 ), selection of appropriate materials of construction, operational control, avoidance of abnormal conditions, on-line pH & corrosion monitoring, use of treatments and inhibitors, fugitive emission controls etc. play an equally important role in affording overall assurance.
4. The inspections were focused on a number of key areas: -
5. This SPC identifies reasons why the management arrangements for assuring integrity of pipework systems are not as comprehensive and robust as for other process plant and equipment. The following list summarises good practice identified during the inspection initiative together with examples drawn from existing guidance and standards including API 570 3 . Collectively these represent a benchmark for the standard to be sought at all Major Hazard sites.
6. The following are novel or interesting techniques seen at some of the sites visited. Operators would not be expected to routinely adopt these to conform to good practice. However, they are considered worthy of note as approaches which help to advance integrity management:
7. The main findings of the initiative are summarised below. Feedback was given to Operators at the end of each visit, with the details recorded in a follow up letter.
8. None of the process piping systems in the sample inspected gave cause for serious concern. Individual shortcomings where identified were reported back at close out meetings and by follow up letter. No notices were served during this round of visits.
9. Recommendations for improvements and remedial actions will be pursued either through specific follow-up visits or included as part of the site COMAH intervention plans.
10. Presentations have been given at seminars and this SPC will be made available to the Operators of the sites visited. Feedback will also be given to relevant trade associations and bodies such as UK Petroleum Industry Association (UKPIA), Chemical and Downstream Oil Industries Forum (CDOIF), Engineering Equipment and Material Users Association (EEMUA) and other stakeholders if opportunities arise.
11. The UK's Major Hazard Industries involve many processes where failure of plant and loss of containment have the potential for disastrous consequences. Pipework and piping systems represent a significant proportion of major equipment failures and this SPC explains some of the reasons why this is the case.
12. In consultation with the Refineries Issues Group, Mechanical Engineers in CI and CD along with their regulatory colleagues carried out a number of inspections at the UK Refineries. Refineries were targeted first because:
13. A standard letter was sent to operators in advance, outlining the objectives and scope of the intervention. It also gave an indication of those site personnel best placed to assist. A standard form was used to record information and act as an aide-memoir.
14. Inspections generally lasted 2 days, with time spent before each visit examining company procedures and documentation. Information given in the COMAH Safety Report was used where available. Operators were also asked to provide details of any pipework related failures and near misses. A number of representative piping systems were chosen for verification purposes. These were mainly drawn from the Safety Report although local knowledge, particularly that of the site Regulatory Inspector, was also important.
15. Assuring integrity of pipework systems, especially on large, major hazard sites, is a significant challenge for duty holders. It can represent a far more complex process than that for other plant such as vessels and machines.
Some of the difficulties are:
16. Nine sites were visited over a period of just less than a year Sites visited. All began with operators presenting an overview of their Engineering Integrity organisation. This was generally followed by discussions on the value and application of the procedures. Enquiries were then made into the pipework inspection selection process and the extent of site activity.
17. Other matters covered during initial discussions included resources and competence issues, use of failure data, auditing techniques etc. The process continued by identifying the main features of the systems selected for the verification phase, checking the relevant P&IDs & Isometrics, and then carrying out a visual inspection of the systems on site. Completion of the exercise involved scrutinising the records of those systems selected for verification.
18. A major part of the interventions was the physical examination of a range of piping systems. This made possible judgements on the actual condition of the plant, afforded a check of the methodology, effectiveness and exactness of the process. It also provided the root of enquiry into registration and classification principles.
19. Identifying representative systems for verification was not straightforward. Systems were selected to cover both those with aggressive deterioration mechanisms and a high probability of failure, and those with a low failure probability but where potential consequence was high. Both on and off-plot systems were represented. Although not considered in a major accident context, utilities were also examined during the inspection.
20. As part of the exercise, checks were also made in regard to topic specific areas including:
21. It is important to recognise that good policy and procedural documents do not necessarily translate to first-rate integrity management and controls. Nevertheless there was an expectation that the companies visited would adopt and maintain high quality policies and procedures. There was also an expectation that references to industry specific codes described in this circular would be extensively used. However, this was not always the case.
22. Considerable variation was seen across the sites. But some common shortcomings were found. Almost without exception documentation was not up to date (e.g. referencing outdated legislation or inspection procedures that were no longer employed). Navigating some documentation was a challenge in itself. Inclusion of corporate and site procedures complicated the understanding of the processes in some cases. In others inconsistencies and duplication of information was common. Two instances were seen where site procedures mirrored those of the 3rdparty Independent Inspection Authority, but the site versions had not been revised and updated.
23. In a small number of cases the policy documents and the supporting procedures added little or no value to the integrity management process. In one case the classification/criticality procedures described in a key document differed substantially from that given in the Safety Report. Rationalisation and simplification of procedures is clearly justifiable in some instances.
24. At most sites integrity management procedures were migrating from conventional time based schemes to fully or partially risk-based techniques. These changes were often linked to the introduction or updating of computer based maintenance/inspection systems. Only in a handful of cases was this transition complete. A degree of catch up was taking place regarding implementation, training and administrative elements.
25. With one exception the inspections revealed little detailed consideration of the API codes and standards, especially API 570 3 /574 4 . Awareness of the codes by technical staff was often good but the recommendations and procedures were not commonly applied in practice. Questions of 'where and how to look' and 'the extent of inspection', were very much left to local inspectors.
26. The majority of procedures did provide some basic information on failure modes and inspection techniques. However, most did not include details of site-specific issues. For example:
27. With the exception of one site where very detailed guidance had been produced, the value of providing specific information on those factors impacting on integrity at a unit level has generally not been recognised.
28. There was frequently an acknowledgment of common inspection practices. But only limited efforts have been made to up-date this information by incorporating more modern and sophisticated NDT techniques, even where these were regularly employed. Information detailing the strengths and weaknesses of the various methods - especially relating to how these may be influenced by local factors - was very limited.
29. There appears to be little technical information and guidance to assist plant inspectors in targeting inspection effort. The link between anticipated degradation, the likely places affected, and the most appropriate techniques to identify it were not well documented. Considerable reliance is placed upon inspector judgement to correctly identify the vulnerable areas and scope out the degree of inspection. This in turn relies heavily on the competence of inspection engineers. Although occasionally captured by audit, almost no peer review and oversight of inspector judgements was apparent.
30. All sites visited utilised failure and near miss data to focus on integrity issues though the degree varied significantly. There was a marked contrast between sites where failure/near-miss data was employed as a tool to actively monitor and steer actions to improve integrity and others where the detail was lacking. In the best cases operators were able to demonstrate how full use of this information allowed problems/trends to be identified and measures taken to address the problem areas.
31. At one site, where diversity of operations made ownership and boundary limits of piping systems particularly complex, an “ownership blueprint” was being developed. The detailed principles were not yet fully established. However, the aim was to produce clear definitions of owners and users. The definitions take into account factors such as originating and receiving assets, single & bi-directional flow, change points, along with inspection and maintenance arrangements. A number of examples illustrating the proposals were included in the document. If instituted correctly the arrangement would represent a step change in resolving what has proved a difficult problem at many sites.
32. Whilst not an end in itself, arguably the most important stage in the process of assuring integrity of pipework systems is identification for registration. Decisions are made about whether systems (or parts of them) will be subject to formal periodic inspection. Judgements can then be made on the frequency and scope of inspection. The rationale supporting these decisions should be logical, clear, and carefully documented.
33. One of the main objectives of the intervention was to quantify the relative proportions of registered and unregistered systems or lines and determine the rationale behind selection. The question put to Operators was, “Are there any pipeline systems at this site, inside or outside of battery limits, containing hazardous fluids, which are unregistered, not inspected, and, should a failure occur, have the potential to cause an unacceptable event?” However, Operators found this question difficult to answer. The following discussion offers some possible reasons for this.
34. Processes to identify and register pipework systems for formal in-service inspection only really began in the early to mid 1990s. A principal motivational factor was probably recognition of the requirements in 'Pressure Systems and Transportable Gas Containers 1989' for Written Schemes of Examination. Previously, inspection of pipework was generally more ad-hoc. It was very dependant on local knowledge, experience of deterioration, or obvious high consequences of failure. Consequently the processes for pipework inspection, integrity management and data recording are not nearly as mature and well developed as those for pressure vessels.
35. The process of registration varied across the sites visited. But almost all began by identifying those lines, often described as Class A systems, which fall within legislative requirements (e.g. PSSR 2000). Those that do not (Class B) are left for a second pass. Estimates varied considerably, but Class A systems may account for as little as 30% of the total. Operators demanded unambiguous evidence of both serious consequences and deterioration mechanisms before registering Class B systems.
36. Understanding the process of selection proved difficult in some cases. In one example a computer software-based scheme was used, but with no supporting documentation to describe the rationale supporting the outputs.
37. Other schemes included paper-based procedures using decision trees as a screening tool. Professional judgements relating to extent of size and consequence of release were permitted, but again with little supporting guidance. Generally estimates were based on size of defect (e.g. a hole size < 7mm was considered not to have the potential to lead to a major accident). Factors such as inventory, detection capability, speed of isolation etc. were all taken into consideration. But records of how decisions had been reached were vague and often non-existent.
38. Often, it appeared that the method was weighted towards confirming that systems could be left 'unregistered' rather than capturing those for which formal registration was appropriate. Rightly or wrongly advantage has been taken of the section in the ACOP to the Pressure Systems Safety Regulations, which states 'the effect of Regulation 8 is to enable the exclusion of most pipework from Written Schemes of Examination where appropriate'.
39. A majority, if not universal, position appeared to be that where no deterioration mechanisms were identified then there was no need to register or include in the inspection programme. This is at odds with most other equipment at high hazard plants, especially vessels. There was wide variation in the extent of inspection coverage and abundant evidence of systems with no inspection history.
40. API 570 3 may be unhelpful here. The code suggests thickness-measuring locations can be eliminated for piping systems with extremely low potential for creating a safety or environmental hazard, or those on non-corrosive service. It is important to recognise that a system may still need to form part of an inspection programme even though thickness measurements are not required. HSE would find it difficult to accept a low probability of failure alone as grounds for elimination where the potential consequences of failure are significant.
41. Where inspection of vessels found little evidence of deterioration this was often used to justify not including associated piping systems. Judgments like these require great care. Duty conditions and materials of construction rarely remain constant throughout a system. Little evidence was found of schemes being reviewed significantly once established.
42. As a result the likelihood of failure from material degradation was generally decisive. Systems where the probability was assessed as low or negligible were often not registered even though the potential consequences of failure were high. The obvious weakness is that if the degradation assessment is flawed then the system may be open to threat. It is not uncommon to find that failures have occurred because an activity or condition has been overlooked at the evaluation stage.
43. Typical examples include:
44. Such instances highlight the weakness and risk of a limited or no inspection regime as suggested in IP13 5 and the API 570 3 advice on elimination of TMLs.
45. There was almost total agreement among the Operators involved that the present schemes were not as thorough and comprehensive as they should be. Of particular concern were those areas where the predicted consequences of failure are significant. Invariably these had been excluded on the basis of assumptions of low degradation and thus low failure probability. However, this argument cannot be sustained without inspection evidence to confirm these assumptions.
46. Operators were advised to implement suitable inspection programmes for these areas to provide baseline data and necessary integrity assurance.
47. The prospect of the HID intervention visits had clearly stimulated much thought by the operators. Almost all have moved, or are intending to move, to full RBI based assessment or equivalents for their selection procedures. Substantial investment has been made by some in order to facilitate these changes. It is anticipated that the new systems will increase the proportion of registered pipework - in some cases from 20% to 80%. This should address the issue of non-inspected pipework. The implementation of the new systems will take a substantial period of time for many sites. An interim inspection programme to address those areas with no inspection history more quickly will be needed. The results of these interim inspection programmes will not only deliver integrity assurance in the shorter term, but feed into the knowledge base upon which RBI assessments are based. HID has produced internal guidance on RBI 6 , including references to findings from HSE sponsored research.
48. Identifying and targeting 'at risk' areas of piping systems using RBI methodologies is still subjective and reliant on assumptions to a degree. The phrase 'expect the unexpected' is probably more valid for pipework than any other item of process plant. Failures still occur because of mistakes or omissions at the input stage. Safeguards should be embedded into the process to minimise the chances of wrong assumptions or other incorrect inputs. Speculative inspection to validate judgements is one way of providing assurance. Peer reviews of procedures and assessments are others. Early research on RBI assessments 7 has revealed some quite dramatic inconsistencies.
49. Nevertheless HSE supports the move to more robust and systematic regimes. Though resource intensive in the first instance, the analysis and rigour of the assessment process carried out by a multi-disciplinary team is arguably the most powerful means to delivering a successful integrity management system. From a regulators point of view it is disappointing that so many providers of RBI systems emphasise cost saving when describing the benefits. However for most sites the move to RBI for their piping systems was driven by a desire to advance the integrity process.
50. The increase in inspection workload at some sites will be substantial and will take time to organise. Advice was given regarding these resource issues.
51. The visits revealed that most inspection departments were adequately resourced although in some cases the number of inspectors had recently been increased. Plant inspectors often perform a multi-tasking role of targeting then carrying out actual inspections, plus monitoring and assessing the inspection findings of NDT contractors. It was interesting that even where there were downsizing pressures the Engineering Integrity Departments did not appear directly affected.
52. Inspection departments generally provided a strong and competent service and were well led. All had accreditation from the United Kingdom Accreditation Service (UKAS) as authorised inspection bodies. There was a mix of Type A (3rdparty) and Type B (2ndparty) inspection bodies. No evidence was found of differences in performance between the two. Activity is always high and during shutdowns and turnarounds the workload can be particularly onerous.
53. Registered pipework would normally be inspected as part of a systematic, inclusive and proactive programme. Campaign type examinations focussing on specific deterioration mechanism such as corrosion under insulation, small-bore vibration related fatigue, buried lines etc, would fall secondary to this. Nevertheless they would complement the broad inspections and provide additional intelligence to the overall scheme.
54. Although most had adopted this method, one company employed a campaign-based approach as their primary strategy. To date it had not led to problems at the site. But under this reactive and rather unstructured regime, large areas of pipework were not inspected. Devoid of any baseline data these systems are vulnerable to failure in our view.
55. An estimated 80% of all pipework examinations are carried out on-stream. Influencing factors include access difficulties, line temperatures, availability of plant etc. Unlike most other process equipment though they are not bound by plant turnarounds and shutdowns. However, this does mean that regular monitoring and scheduling is required (an additional complication). It is in this area that dedicated software can offer significant benefits. Invasive inspection of pipework is not the norm, and is usually restricted to circumstances where failures have occurred.
56. The volume of information arising from pipework inspections is vast. Interpreting the raw data and making informed judgements on fitness for service is a crucial element in the process. The inspection revealed that many operators now use or are considering using, proprietary software tools. Asset Management Tools such as CORTRAN or CREDO can help with the manipulation of the data. These packages can also provide scheduling routines, isometric sketches, data tables, corrosion limit spreadsheets, and retirement dates. A key feature of these systems is that they can identify safety critical factors by generating alarm flags for certain criteria. Not all sites employed computer based technology and one still operated a very sound paper-based arrangement.
57. In general, good use was made of piping isometric drawings for targeting and recording inspection findings. The detail varied considerably, for example, some sketches only showed TMLs. Others included specifications, nominal wall thicknesses, materials, insulation details, support locations and types, access requirements etc.
58. Isometrics can also be of great value at the degradation assessment stage. They show configurations such as deadlegs, elbows, reducers, branches etc. where geometry can significantly influence degradation likelihood. The appropriate level of detail to be shown on piping isometrics is debatable. Nevertheless, whilst their production is expensive and resource demanding, the value of accurate drawings cannot be overstated.
59. Few sites made use of external visual examination checklists. We felt that this was a mistake, as they promote consistency in the inspection effort. They can often be used to identify and record dynamic factors. And they can provide a complete record to support other examinations that may only report by exception. An example checklist is given in API 570 3 . One independent inspecting authority produced an excellent example complete with explanatory notes and acceptance criteria. In another example seen, unit inspectors had produced mini visual-checklists detailing line condition at thickness measuring locations.
60. Use of “state of the art” NDT technology was more widespread on some sites than others. Rapid scan techniques are now being more widely used. Examples include long-range ultrasonics, where tens of metres can be checked from a single test point, Corrosion Under Insulation (CUI) detection without the need to remove insulation, and methods that give thickness data under supports. Full evaluation of the strengths and limitations of these recent techniques is still taking place; however there appears to be far greater levels of confidence now than in the past. Useful guidance on the topic of NDT can be found in the HID Technical SRAG 8 .
61. Only a small number of sites had significant backlogs of inspections with due dates being missed. Where significant backlogs were found proportionate action was taken. Operators were reminded that inspection due dates should only be exceeded by exception and after careful review. A common complaint from inspectors was the time required to produce good isometric drawings. At one site inspectors indicated that their workload did not allow sufficient time for thorough evaluation of the data they were gathering. Some sites are taking action to better integrate inspectors into operating units. The hope is that operational factors, which may impact on integrity, will be more quickly and clearly recognised.
62. The availability of deep specialists such as materials/corrosion engineers varied. However, overall they were not well represented. In some cases where problems had arisen specialists were outsourced. The obvious disadvantage is the lack of site-specific knowledge. One operator employed two full-time specialists and the value they added to the process was obvious. When fundamental changes such as moves to RBI assessment and corrosion loop studies are in progress their input is in even greater demand. As a further benefit, they also delivered training on corrosion issues to inspectors and plant engineers.
63. All inspecting departments were subject to one form of auditing or another. However very little evidence of auditing the actual performance of inspection departments was found. No audits were carried out to determine whether the regimes were technically compliant with good practice. Time constraints are thought to be the main reason. We believe that departments would benefit from having clear performance measures. Examples include: numbers of inspections completed to plan, numbers of releases, overdue inspections, reports to timescales etc.
64. A limited number of Operators had defect assessment procedures and fitness for purpose rules:
65. Some differences of approach were observed in relation to predicting the remaining life/retirement date of piping systems and inspection scheduling. For example, wall-thinning data was used to calculate corrosion rates and retirement limits. Graphs were then extrapolated to predict a retirement date. If the next inspection was due before this date no action was taken. At face value this appears reasonable. However degradation is rarely uniform and so inspection programmes should err on the side of caution. This is reflected in the corrosion rate and half-life inspection principle in API 570 3 .
66. Methodologies for defect assessment and predicting piping retirement limits were sometimes in place, but were not referenced and integrated into site procedures.
67. Even though verification was, by necessity, a sampling exercise, it is fair to say that many anomalies were found. Some related to data inaccuracies, and dubious interpretations when setting next inspection dates. It is very important that a precautionary interpretation of the findings is made initially. If this gives an unsatisfactory answer, more data should be obtained from the plant rather than making optimistic evaluations. Flaws and misjudgements were also found in the registration and assessment processes. Where many such anomalies were found Operators were advised to review their procedures.
68. None of the process piping systems in the sample inspected gave cause for serious concern. Most appeared well maintained although the condition and standard of insulation was poor in certain cases. Process induced vibration was also noticeable particularly at the front end of crude units where 2-phase flow is common. The condition of utility systems especially utility steam was poor in many cases. Operators will need to consider upgrades and investment in these areas. Individual shortcomings were reported back at close out meetings and by follow up letter. No notices were served during this round of visits.
69. Corrosion Under Insulation (CUI, sometimes referred to as under-lagging corrosion or ULC) is still a serious deterioration mechanism affecting pipework on most sites. Many Operators had little in the way of evidence of specific policies and procedures to deal with this problem. In some cases operators were using guidance that was over 20 years old - though this is recognised.
70. Only two operators had up to date information on identification issues and protective measures. One of these was of particularly high quality - their recent internal guidance on prevention and detection of corrosion under insulation identified that many of the worst examples of CUI were either 'self inflicted' or linked to the age of the plant. Pipework 30+ years old is common in refineries.
71. A leading engineering consultancy has also just produced a guide with recommended approaches for the detection of CUI and its management especially in regard of equipment of high susceptibility. Internal HID guidance 11 is available on the topic of corrosion under lagging/insulation.
72. Very few sites had made proactive insulation requirement surveys. Our inspections revealed numerous examples where insulation was no longer required. On one site, CUI was identified as the most credible failure mechanism, yet insulation standards were well below what is acceptable. Design of cladding and water tightness after maintenance and break-ins is not well controlled.
73. An industrial forum, the CUI Forum 12 , has been established to assess new developments, discuss common problems and identify practical solutions on CUI related matters. A guidance document is being considered.
74. CUI remains a serious threat to pipework integrity. Where limited progress was seen, we will monitor the commitment of sites to address the issue.
75. Small-bore pipework failures through vibration related fatigue had been identified as a significant problem. However, this topic appeared to be given a lower priority than CUI. Some sites have taken measures such as removal of unnecessary instrumentation, and reinforcing supports. Several sites were surveying small-bore pipework in an attempt to identify those branches at highest risk. A number of engineering consultancies have recently developed effective methodologies to identify and prioritise the highest risk areas. Some had been employed to conduct these surveys.
76. Knowledge of the UKOOA 13 and MTD 14 publications on small-bore pipework was variable.
77. All Operators were aware of the problems relating to these vulnerable areas. There is no doubt that recent failures have raised their profile. Deadlegs can be created by the way a plant is operated, or when modifications to original design are carried out. Management of change procedures do not always capture where deadlegs have been created. Some operators had completed identification surveys or had surveys in progress. One site had produced a unit-by-unit register, which included an individual hazard assessment for each deadleg. The usual hierarchy of measures was deadleg removal (where possible) followed by other measures such as flushing procedures, material changes and increased inspection.
78. Most areas of buried piping or sections through bunds, across roads etc. are found in off-plot areas (i.e. those that fall outside of unit battery limits). Although these areas are generally considered to be of lower risk, failures can have severe consequences both in terms of safety and the environment. Few sites had procedures detailing how in-service integrity of these pipelines was assured; and in particular guidance on which lines might require unearthing. There was evidence of lines between units not being registered.
79. Cathodic protection was not the normal measure of choice to prevent corrosion related failure. Many lines (normally bitumen coated on installation) were simply buried and forgotten. Maintenance and remedial actions were normally on a breakdown/defect basis and often conducted as project/capital work.
80. Most Operators now appear to realise that this approach is inappropriate. Responses include bringing pipework above ground, use of improved wrapping materials, and periodic inspection using more modern NDT techniques such as long-range ultrasonics. In general, sites are using consequence estimates to prioritise the remedial work much more than they were in the past.
81. Most operators are adopting radically improved procedures and techniques for making flanged joint and bolted connections. Leaks from flanges and associated failures are well documented. Most operators have knowledge of, and are working to, the recommendations given in the UKOOA Guidelines 15 .
82. Not all were adopting controlled bolt loading techniques and flange tagging, especially for the smaller diameter and lower pressure systems. But there was a recognition that improvements could be made. Some Operators were attempting to compile registers of known troublesome joints that required superior controls. One site saw significant benefits following a turnaround where flange-bolting procedures had been radically improved. The exercise had convinced the Operator to extend the process to all their sites.
83. There was generally good evidence that strict procedures are being employed when using on-line sealing techniques. However, it was apparent that some felt under corporate pressure to regard them as more permanent.
84. HSE's position is that temporary repairs are only allowed once all other options have been considered, that they are treated as modifications and that an assessment is undertaken before use, including a structural analysis where necessary. Once installed joints are then registered, made subject to formal inspection and are given a finite service life. They should be returned to original specification at the earliest opportunity. Refer to HID's internal guidance on the topic of temporary repairs 16 for more information on this topic.
85. Increased use is being made of composite wraps to effect piping repairs. This technology, developed for military and offshore use, is now being employed for on-shore repairs. The technique has strict limitations and duty constraints, which are detailed in the technical literature. The suitability of such a repair is a matter for close consultation between the operator and provider.
86. Integrity of process piping issues are becoming more widely recognised and it could be argued that guidance currently available is adequate. However, whilst the API and IP codes have their value, they are petroleum industry based. API 570 3 is refinery specific, whilst IP13 5 focuses more on 'Pressure Piping' and is now of some age. With the introduction of COMAH legislation and the general duty for operators to take all measures necessary to prevent major accidents there may now be a case now for more up to date guidance to help chemical process industries in general. Newer guidance could describe good practice in terms of hazard identification and risk based procedures as well as providing information on contemporary inspection techniques.
87. User guidance encompassing in-service issues of maintenance, inspection, repair, and testing of piping systems, especially for the petroleum and chemical process industries is widely available. American Petroleum Institute code API 570 3 and the Institute of Petroleum code IP 13 5 are particularly relevant.
88. API also publishes a recommended practice document RP 574 4 and specific guidance is given in API 751 for pipework inspection in HF Alkylation units.
89. Pressure Systems Safety Regulations 2000 ACOP L122 17 and the Safety Assessment Federation (SAFed) Guidelines 18 also give information on the inspection of pipework systems but are predominantly restricted to those subject to the Pressure Systems Safety Regulations 2000 (PSSR) regime. In this context 'relevant fluids' and 'stored energy' form the prime basis of selection. ACOP L122 17 advises that pipework need only be included within the formal Written Schemes of Examination if its mechanical integrity is liable to be significantly reduced by corrosion, erosion or other factors - and the release of stored pressure energy would give rise to danger.
90. It is worth emphasizing that the hazards presented by flammable or toxic substances are not considered within the scope of the Pressure Systems Safety Regulations and for COMAH regulated sites this is an issue of some importance. Note: A guideline for the In-service Examination of Pressure Systems Pipework is currently being drafted by SAFed.
91. Other publications such as those by UKOOA on Bolted Flanged Pipe Joints 15 , and Small Bore Tubing Systems 13 plus the Marine Technology Directorate Guidelines 14 provide additional information on specific topic areas.
92. Of the two main guidance documents API 570 3 arguably gives the most comprehensive and practical advice. It contains sections covering inspection practices, frequency and scope of inspection, data evaluation, repairs/alterations etc. The code explains in some detail systems that are susceptible to specific types of deterioration, such as deadlegs, injection points, corrosion under insulation etc. RP 574 4 gives information on recording techniques and shows a typical piping isometric sketch with example Thickness Measuring Locations (TMLs).
93. There is no definitive information on the extent and volume of pipework on refinery sites that require formal registration. However, Section 1.2.1 of API 570 3 does give clear guidance on identifying and classifying those systems that should be included. Basically the code states that any pipework in hydrocarbon or toxic service should be registered. Once identified, the scope and frequency of inspection can be determined based on history, operating conditions, and consequence of failure etc.
94. This is a difference of substance from the guidance given in IP 13 5 which states that registration (apart from systems which fall within relevant national legislation) should be limited to those systems where degradation is known or suspected, and where failure would give rise to an unacceptable situation. This parallels the position for pipework systems given in ACOP L122 17 to the PSSR, albeit extending the scope beyond the dangers of stored energy. Arguably, it is this reflection of the PSSR ACOP in a document intended for use in the petroleum industries that is responsible for many of the ambiguities and uncertainties with registration processes in the past.
95. Note: Currently there is no HSE guidance on piping specific issues for process plant.
96. Codes, Standards and Guidance gives full references to the most relevant standards.
For further information on the contents of this circular please contact: HID CI Mechanical Engineering Specialist Team (CI 1F) 0131 247 2027
Total Fina Elf Lindsey Oil
ICI North Tees
Conoco Philips Petroleum
BP Oil UK
BP Amoco plc Complex
Elf Oil UK
Note: Local circumstances dictated that the Conoco Phillips Refinery - Humberside and Shell Refinery - Stanlow were not visited during the project.
1. Chemical Plant Integrity: HID national inspection-project 2003/2004 SPC/Enforcement/60
2. Process Piping - ASME Code for Pressure Piping - ASME B31.3 2002
3. Piping Inspection Code: API 570 2nd Edition 1998
4. Inspection of Piping, Tubing and Fittings: API RP 574 1990
5. Pressure Piping Systems Examinations: Model Code of Safe Practice IP 13 2nd Edition 1993
6. Risk Based Inspection (RBI) - A Risk Based Approach to Planned Plant Inspection: SPC/Tech/Gen/46
7. Risk Based Inspection - A Case Study Evaluation of Onshore Process Plant: Research Report HSL/2002/20
8. HID safety report assessment guide: Technical aspects pm/permissioning/02 technical measures document : inspection / non-destructive testing (ndt) (Manual previously know as “Level 3 Guidance for the Assessment of Technical Aspects of COMAH Safety Reports)
9. Manual for Determining the Remaining Strength of Corroded Pipelines: ASME B31 G
10. Recommended Practice for Fitness For Service: API RP 579 1stEdition 2000
11. Under-lagging Corrosion of Plant and Pipework: SPC/Tech/Gen/18
12. Contact point for the forum: John Thirkettle, CUI Forum e-mail: firstname.lastname@example.org
13. Guidelines for the Management, Design and Installation and Maintenance of Small Bore Tubing Systems: UKOOA 2000
14. Guidelines for the Avoidance of Vibration Induced Fatigue in Process Pipework: Marine Technology Directorate 2002
15. Management of Integrity of Bolted Pipe Joints: UKOOA Guideline 2002
16. (SPC on Temporary Repairs is in preparation, title to be decided and details will appear here in due course)
17. Safety of Pressure Systems - Approved Code of Practice L122
18. Pressure Systems Guidelines on Periodicity of Examinations SAFed 1997