Ian Partridge, John Wintle and Julian Speck
Ian Partridge ( firstname.lastname@example.org) is a principal pressure vessel engineer who undertakes a range of fitness for service assessments and leads TWI's participation in the Corrosion Workgroup in the European FITNET project.
John Wintle ( email@example.com) is a structural integrity consultant at TWI as is the vice-chairman of the Institute of Mechanical Engineers' Pressure Systems Group, and leads TWI's participation in the European RIMAP project.
Julian Speck ( firstname.lastname@example.org) is TWI's structural integrity department manager, responsible for FFS and RBI projects and development activities.
Deadly corrosion failures
A few years ago, TWI investigated a corrosion failure in a 30inch crude oil pipeline ( Fig.1) that regrettably led to an explosion and fire, and the death of several operating personnel. The pipeline was designed to ASME B31.4 and the investigation found that corrosion resulted from the break-down of the external coating. The exposed area of pipe was too large for the cathodic protection system.
Fig. 1. Corrosion failure of crude oil pipeline
Pitting corrosion initiated at several locations that coalesced to over a large area to cause failure by rupture. The lost production from this failure was 300,000 bbl/d. The corrosion in this pipeline was not detected before failure. However, if corrosion is found in service pressure equipment, there are safe guidelines available for inspection engineers to assess the fitness-for-service (FFS) of corrosion damage.
FFS procedures have been developing since the late 1960s, and were initially, simply reverse design rules. For example, the remaining wall thickness at the bottom of a locally thinned area (LTA) was input into the Code design pressure-thickness equation to calculate the maximum allowable work pressure (MAWP), Fig.2.
Fig. 2. ASME equations for vessels under internal pressure (in terms of inside radius for longitudinal seam welds).
Several FFS approaches for assessing corrosion LTAs are available, Table 1. This table excludes proprietary tools incorporated in assessment software, eg. PCORRC (Battelle), RSTRENG (PRCI), FEA Flaw (SRT), etc. With the proliferation of procedures and tools, the choice of FFS assessment procedure is becoming somewhat more difficult. The most widely used FFS procedures (even though they may not give the same results), are the recommended practice for assessing fitness-for-service published by the American Petroleum Institute in API RP 579 (second edition due in 2006), and the guidance for the assessment of flaws in structures published by the British Standards Institute in BS 7910 (the successor to PD 6493, revised in 2005).
|ASME B31G, 'Modified B31G' (also known as the '0.85-dL' method)
||For pipelines; Conservative; May be superseded by API RP 579?
|Reverse Design Code
||PD5500, ASME, etc; Simple; Exploits actual thickness versus code requirements
|PD 5500 and ASME code cases
||Considering, for example, use of actual strength rather than SMYS
|DNV RP F101
||For pipes and piping; includes partial safety factors (PSF) and external loads
|BS 7910 Annex G
||Originates from British Gas in-house procedures for pipelines
|British Energy R6 collapse solutions
||Suitable for rapid assessment of circumferential corrosion
|API RP579 Chapters 4, 5 and 6
||General, local and pitting corrosion; principally design code-based
|Shell Global Solutions handbooks for piping, elbows and pressure vessels
||In-house procedures; combination of methods: RP579, R6 and EPERC
Why is the use of FFS limited?
While users and regulators across industry now increasingly accept flaws and damage in equipment assessed as fit-for-service, the differences between the available procedures and the implied safety margins are not widely known. There are difficulties in obtaining the data and differences in the engineers' skills and knowledge required to make good assessments, and even disagreements amongst 'the experts' about the best procedures. As a result, the benefits of FFS assessment are not (yet) as widespread as might have been expected from recent publicity.
In 2001, TWI carried out a worldwide industry survey on the use of FFS procedures. All sectors of industry were represented, and many were major users of pressure equipment mostly offshore oil and gas, petrochemicals, refining and fossil power companies. Respondents to the survey gave many reasons for undertaking FFS assessment, in order of importance, as follows:
- Determining the residual life of damaged plant;
- Ensuring safe operation beyond design life;
- Down-rating damaged plant below design;
- Demonstrating tolerance to defects within a safety case;
- Extending inspection intervals; and
- Reducing duration of outage and shutdown.
It is obvious that some of these reasons do not involve actual flaws or in-service damage in equipment. FFS is often undertaken assuming postulated flaws or damage, to demonstrate the margin of safety against failure in ageing equipment.
Interestingly, only 43% of respondents indicated that their safety regulating authority accepted FFS assessment for safety-critical pressure systems. There is evidently still a strong feeling among safety regulators that flaws andin-service damage in pressure equipment should be repaired. There could be many reasons for this reluctance to accept FFS assessment. For example, there are variations in the inherent safety margins in different pressure vessel design and construction codes, Table 2.
The origins of FFS
Code committees have always recognised the occurrence of welding flaws in fabricated equipment, and have set permissible levels and sizes for flaws. These acceptance criteria sometimes require a large number of weld repairs that are not only time consuming and expensive but could also be detrimental to integrity. It has long been recognised that these standards can be very conservative. A procedure for assessing fitness for purpose (pre-service) of welding flaws was therefore developed. Early research at TWI characterised the fracture behaviour of welds containing defects by means of crack tip opening displacement (CTOD), leading to the development of BS PD6493 for the assessment of flaws infusion welded structures.
The development of PD6493 for engineering critical assessment (ECA) was fuelled by the requirements of the oil and gas industry to exploit the UK's North Sea reserves. Not only was there a need to achieve a minimum numbers of weld repairs, the owners had to assure the safety of the equipment to the possibility of fatigue cracking in the hostile environment. There was therefore later a move to incorporate the assessment of the fitness for purpose of welds subject to fatigue in PD6493.
Another early driver for integrity assessment came from the nuclear industry where it was necessary to demonstrate high integrity of pressure vessels. Subsequently, fitness for purpose assessment became vital for justifying the safety of nuclear vessels that were difficult to inspect or repair. These drivers led to the development of the assessment procedures in ASME XI and the UK's Nuclear Electric R6 procedures.
Recent FFS developments
The fossil power and petrochemical industries drive for higher plant efficiency, and safer and longer operating life, has extended the development of FFS technology. This drive led to a need for a reliable creep and creep crack growth assessment procedure for real (in-service) or design allowable (pres-service) flaws. Nuclear Electric developed the R5 procedures, and later BSI published the only document for EU countries providing guidance on life estimation of high temperature components containing flaws, namely BS PD6539 (which is now incorporated in BS 7910).
These high temperature assessment procedures, irrespective of whether or not they originate in the UK or USA, continue to develop and are not yet universally accepted. For example, the only standard available to provide guidance on creep crack data analysis is ASTM E1457, and the high temperature procedures intended for Section 10 of API RP579 are still in draft, even though RP579 was released in 2000.
Operators of pressure equipment in the refining industries are particularly interested in assessing in-service corrosion damage. Procedures for assessing corrosion damage had previously been developed from research work, for example, the ASME B31G (1991) manual for determining the remaining strength of corroded pipelines. After a significant review of world experience (originally initiated by the Material Properties Council), consolidation of existing procedures and significant revision in the 1990s, API produced the Recommended Practice API RP579.
In the EU, also in the 1990s, the European Commission sponsored the SINTAP project to review available FFS procedures to update guidelines that could be more widely utilised. This started a process of harmonisation within Europe which is being completed through a network called FITNET ( www.eurofitnet.org), which will run until the end of February 2006. FITNET's primary activities include:
- - reviewing existing procedures and research findings on fitness-for-service;
- - generating case studies and educational material;
- - holding public seminars and training workshops; and
- - liaising with CEN on standardisation.
In 2005, a committee was formed to produce a European (CEN) standard on FFS, in the form of a CEN Workshop Agreement. FITNET exchanges information with API, and to this end TWI participates in the API refining and equipment standards committee developing API RP579, providing an informal link between the US and EU FFS development activities.
If the through-wall depth of corrosion is greater than the corrosion allowance for pressure equipment, procedures such as those in API RP579 or BS 7910 may be used to determine (or not) fitness for safe continued service. They have been shown to produce safe assessments when compared with burst test results (for simple geometries like pipe sections). However, plant inspection engineers are frequently concerned about 'difficult' corroded pressure vessel components like nozzles, Fig.3. Such geometries require finite element analysis (FEA) techniques to assess the integrity of the corroded pressure components.
Fig. 3. Corrosion on a nozzle at a break in thermal insulation (courtesy of FITNET)
FEA normally requires an accurate description of the corroded surface (which can be time consuming to determine) and is therefore not always practical, or alternatively, simplification of the damage can lead to significant conservatism. The actual failure pressure in a corroded pipe will be governed by the details of the characteristics of the corroded surface, and may vary considerably from the predicted pressure for a smooth pit. In addition, the predicted failure pressure may be non-conservative for corroded regions of greater axial or circumferential extent, or where corrosion pits are grouped in closely spaced clusters.
FEA can give accurate predictions of failure (burst or leakage) pressure when the model has been validated. Validation in this context does not necessarily mean burst testing. However, the FEA criterion for failure (eg. 'failure occurs by plastic collapse when the von Mises stress level at the external wall surface in the corroded pit reaches a true stress level of the material UTS') should ideally have been validated by physical testing, Fig.4. Caveat Emptor: always ask your FEA contractor to prove they have validated their in-house FFS modelling procedures against actual burst test data.
Fig. 4. Section of local collapse of a pipe ligament after burst testing, and the FEA modelling mesh around the isolated pit
API versus BSI corrosion FFS procedures
API RP579 has separate procedures for dealing with general metal loss (Section 4), local metal loss (Section 5) and pitting (Section 6). The BS 7910 Annex G procedure covers both general and local metal loss in pipes and pressure vessels and is similar but subtly different to that used by API RP579 for local metal loss.
Simply stated, the API Section 4 procedure for assessing general metal loss determines the average and minimum thickness from a grid of spot thickness measurements over the corroded area. The pressure component is assessed as fit-for-service if this averaged area is thicker than the ASME code minimum design thickness (tmin ) for the part, and the minimum measured thickness within the grid is greater than the larger of 0.5tmin or 2.5mm (0.1inch).
The API Section 5 procedure for local metal loss determines a remaining strength factor (RSF) from which a reduced safe working pressure is calculated as a fraction of the original maximum working pressure. The basis of the procedure is to treat the locally thinned area as a part through-wall flaw, and to use the form of the equations developed by Battelle for local bulging (plastic) failure in pressurised cylinders.
Again simply stated, the procedure in BS 7910 for the assessment of corrosion in pipes and pressure vessels is based on a reserve strength factor (another 'RSF'; it uses the same form of the equations as for API RP579's RSF). The differences between the API and BSI equations for RSFs include different constants and failure criterion, and the BS 7910 method is not based on the minimum (ASME) code design thickness.
Consider a typical corrosion problem for piping, Fig.5. As an example of the differences in the RSFs predicted by the two procedures, assume the pipe is SA 516 Grade 70 with the following dimensions: D = 762mm (30inch); tmin = 9.0mm (0.35inch); tnom = 9.8mm (0.39inch); and the corroded length = 1,000mm (39.3inch). For this particular case, for a minimum remaining pipe wall thickness of 8mm, RP579 predicts a RSF of about ~0.85 and BS 7910 predicts a RSF of about ~0.70. The difference is due to the use of the code minimum as opposed to nominal thickness of the pipe. So with differing estimates of the remaining strength, the use of either assessment procedure gives rise to different judgements about the safety of the pipe.
Fig. 5. Corrosion at contact point at a pipe support (courtesy of FITNET)
Beware of structural discontinuities
Wherever there are changes in geometry of a thin pressure vessel shell, such as between a cylindrical section and a dome end, or a cylindrical section and a conical section, the 'incompatibility' of displacements caused by pressure loading in the sections gives rise to significant local (longitudinal) bending. The radial deformations of the shell and the dome are different, so are reacted by internal shear forces (Q) and moments (M), Fig.6. The shear stress produces inward bending of the shell, resulting in compressive circumferential strain, and tensile longitudinal strain.
Fig. 6. Loading at the discontinuity between a shell-to-dome weld
FFS assessment procedures have not been adequately validated (other than by FEA) for these additional, secondary stresses since the available burst test data were almost always obtained from simple corrosion flaws in straight pipe. All FFS procedures, at screening level, are cautious and warn the user that the assessment of corrosion at discontinuities is not permissible. It should be noted that majority of structural discontinuities are also normally at welds, and welds may contain flaws and/or have different toughness and tensile properties.
Most procedures permits assessment of corrosion at welds provided that crack-like defects are not present, the fracture toughness properties of the weld metal and heat affected zone (HAZ) are adequate to prevent brittle fracture, and the weld metal is not significantly under or over-matched in terms of strength. FEA-based assessment (API RP579 Level 3) is allowed in these cases but beware: few contractors have the FEA experience or validation cases for these geometries.
Is any discontinuity worse than a nozzle?
Corrosion can lead to the failure of nozzles through the general collapse of the nozzle (ie. global collapse), or leakage of the corroded ligament (ie. local collapse, Fig.4). Global collapse of corroded nozzles can be avoided by assessing the nozzle using any of the following methods: the ASME VIII Division 1 'area replacement rule' ( Fig.7); the Welding Research Council's method (WRC 107); or the BS PD5500 elastic stress design rules. The first two methods have been adapted for use in the 2000 edition of API RP 579. The choice of the assessment procedure to use for a corroded nozzle is not always dependent on which standard was chosen to construct the vessel. Instead the choice of assessment method is dependent on the input parameters available and which method will ensure the integrity of the vessel without being too conservative.
The stress distributions at un-corroded nozzles in pressure vessels are an order of magnitude more complex than at other discontinuities (head-to-shell joints, etc). The principle stresses at the inside surface of the crotch corner are in the axial plane of the main shell, Fig.8. This is in the absence of any superimposed piping loads and moments, which would normally be considered in the design of the nozzle. (In fact, most corrosion FFS assessment procedures generally do not apply to nozzles of any type, that are subject to external loads from piping).
Fig. 8. Complex principle stresses along the inside surface at a shell-to-nozzle joint
Neither the area replacement rules, nor the elastic stress arguments of BS PD5500, nor the Welding Research Council method were formulated with the aim of providing a FFS assessment method for corrosion. API RP579 has easily adapted the area replacement rules (i.e. reverse design) to prevent global failure of a corroded nozzle, but this does not explicitly safeguard against local collapse of the corroded ligament.
In other words, the use of a global collapse criteria is not always sufficient to ensure fitness for service. It should also be noted that in previous research at TWI, in a comparison of the minimum wall thickness obtained using these three methods, no method gave consistently lower allowable minimum wall thicknesses compared to the others. Furthermore, the effect of non-uniform (localised, not generalised) corrosion on the local stress distribution at a nozzle will be complex, with respect to ligament collapse. Consequently, no standard method of nozzle corrosion assessment has yet been universally accepted worldwide. (The new nozzle assessment procedure being developed within the FITNET project will actually be a strain-based method).
The future of corrosion FFS procedures
Since the code committees in the US and EU continue to borrow good ideas from one another to make incremental improvements to their own procedures, the future of FFS is likely to be one of harmonisation. The extent of this will only be limited by the people involved in these committees. Although the industry survey shows there is still a degree of reluctance to rely on FFS assessment, the endorsement by API, BSI and CEN (soon), should give its use more confidence and impetus.
Although API RP 579 and BS 7910 are the most commonly used procedures for FFS assessment, the choice between the two will depend on company policy, the attitude of the national regulating authority, the sophistication of the end-user, and access to the necessary data and sources of information, training and support.
- BS 7910 is applicable to all equipment and materials and is written in a more generalised manner without reference to a particular industry, design code or material and thereby allows users to use their judgement about safety margins.
- BS 7910 requires some technical expertise at all levels of assessment, with the level of conservatism decreasing with increasing assessment level (1 to 3).