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Life Management Of Above Ground Atmospheric Storage TanksC.J. Moss, RR Griffiths, A Bishop, M Dinon
The integrity of tanks needs to be well managed because they can contain a large inventory of hazardous materials and because of the high costs such as cleaning and waste disposal prior to inspection and maintenance. The WTIA Petro Chem - Refinery " Save Money and Re-engineer with Technology" (SMART) Group has collectively identified tanks as an area where collaborative work would be beneficial.
The damage mechanisms associated with tanks can be complex and varied. Mechanisms include underfloor corrosion (where cathodic protection and drainage issues are important), internal corrosion (where the contents of the tank, the presence of species such as sulphate reducing bacteria and temperature control the corrosion rates) and non-corrosion related mechanisms such as differential settlement.
When risk is defined as the product of likelihood and consequence, it is apparent that tanks deserve high profile in a risk directed inspection program. It is maintained in the paper that it is possible to develop inspection scopes directed on the basis of risk. Such an approach permits the use of resources to be optimised while the overall costs of maintenance are minimised. Inspection and turnaround costs may be minimised and the risk of business and safety impacts reduced to an acceptable level whilst meeting statutory occupational health, safety and environmental requirements.
This paper reviews Australian requirements pertaining to the scope and interval of tank inspection and identifies gaps in requirements. Inspection needs are presented and techniques such as acoustic emission and floor scanning are discussed. Case studies of tank asset management are presented.
Tanks have been around since the beginning of hydrocarbon production. However, relative to pressure equipment, limited information is available for tank integrity management. Tanks vary considerably in size, from small Australian Standards (AS) 1692 class 4 or 5 tanks, where the size is typically 50,000 litres, to American Petroleum Institute (API) 620 and 650 tanks where the size may be tens of millions of litres. In the ten years of life assessment and life extension conferences in Australia, to the authors' knowledge, few papers have been presented on tank issues. Perhaps the perception that tanks are simple, ambient pressure equipment leads to them receiving less attention in the technical literature. Additionally, the generally high reliability and perception of tanks as infrastructure rather than plant has meant that tank maintenance approaches have tended to be reactive. Whatever the case, review of tank design and operating experience shows that tank issues can be complex and responses to leaks have been costly and anything but simple.
The failure of a tank can have several undesirable effects such as endangering personnel, affecting the environment and interrupting the operator's business. In a 1988 API worldwide survey, tank ruptures accounted for 5 % of the 132 releases that occurred worldwide between 1970 and 1988 but accounted for almost 19 % of the released material. An example of a failure with dramatic results was in January 1988 in Pennsylvania, where 500,000 gallons of fuel flowed from an above ground tank into the Monogahela River, the major source of water for many local towns. The cost of clean up, damage to the environment and adverse publicity associated with this and other releases spawned present tank regulations and the development of API 653.
Whilst pressure integrity management is well-developed in standards such as AS3788, tank integrity requirements in Australia are evolving. Whether published standards for tank integrity are available or not, it is apparent that well planned preventive, rather than reactive, measures should be taken in tank maintenance and reliability. It is interesting to note that in the USA, tank regulations and rules generally focus on mitigative rather than preventive aspects; for example leaks and spills are mitigated by secondary containment rather than prevented by design and inspection. The importance of inspection and condition monitoring in avoiding failures, maintaining safety and optimising availability is unquestionable. However, in a competitive business environment, down time for inspection requires considerable justification.
Facilities with tanks often present additional risks beyond site risks such as potential injury to site personnel, damage to equipment and lost business. Tanks are often located in areas of environmental value or, because of the encroachment of suburbia, are close to the community. Furthermore, incidents may create unfavourable publicity through media coverage. Consideration of the cost of litigation and fines from accidental releases alone can warrant setting up an inspection program. Companies therefore require a consistent approach for assessing tank integrity and maintaining compliance with industry standards and regulatory, that is, community requirements. Such an approach must
This paper presents a of information resources, regulatory requirements and describes case studies of tank asset management from three companies. Gaps and opportunities are presented to promote dialogue and raise awareness of needs.
Three SMART groups representing the pipeline, power generation and petrochemical industries were formed shortly after the launch of the Ozweld Technology Support Centres Network Project in late 1998. The Petrochemical group has 12 member companies from refineries, gas plants and chemical plants. The SMART Group has been successful in identifying technological needs by creating a discussion forum at company level and a cooperative spirit of working together, despite participants being associated with different companies. A fundamental aim of each SMART group is the creation of a close network of key participants from that particular industry and to identify " expert technology tools" needed to help improve industry viability. In line with this theme, the SMART Petrochemical group identified a need to review the most effective NDT techniques for tanks to improve tank asset management.
In Australia, tank in-service inspections are generally identified in petroleum regulations, occupational health and safety regulations or dangerous goods regulations. Details vary from state to state but most make reference to AS1642, AS1940 and AS3788, which address design, construction, operations and maintenance in varying levels of detail. Beyond Australia, there are several design codes that provide good assurance on fitness for service: in particular, the standards and recommended practices produced by the American Petroleum Institute (API) are recognised as world class. Tank selection has historically been a complex process of optimising an array of requirements such as design, capacity and cost. Other factors include corrosion prevention systems and environmental regulations. In planning to design and construct new tankage, there are ample standards geared to provide agreement on design and fabrication between the supplier and purchaser. Such standards ensure that the tank will not fail when put into service and were not intended to deal with long term maintenance and inspection. There are a number of API standards and recommended practices which provide guidelines on design, fabrication, operation, cleaning, inspection and repair of tanks and which can be used to develop tank integrity programs and procedures. Selected information is contained in Appendix 1. The most important guide on in-service integrity is API 653.
|Summary of Useful Tank Inspection and Repair Standards and Guides|
|AS1692-1989|| Tanks for flammable and combustible liquids|
Details design and construction requirements for tanks, but makes no reference to post-construction inspection issues.
|AS1940-1993|| The storage and handling of combustible liquids|
States that a procedure for the inspection of tank vents and fittings shall be established to ensure that pressure/vacuum and emergency tank passages are clear and any relief valves are operating correctly. Such inspections shall be carried out at periods not exceeding 12 months, or as necessary depending on the application.
A procedure for the maintenance of tanks, including testing, inspection and monitoring. Clause 9.8.14 and Table 9.1 detail record keeping, repairs, limited filling heights, testing and inspection frequencies for category 6 tanks. Operational inspections shall be carried out monthly, shell, bottom and roof integrity related inspections shall be carried out at a maximum interval of 10 years. States that the minimum allowable floor thickness is 4mm.
|AS3788 - 1996|
Appendix T (Normative)
| In-service Inspection of tanks|
Deals with API 620 tanks, calls up AS1940 inspection interval category 6, ie. 10 yearly internal inspection required. Also references API 653, AIP CP 16 (10 yearly internal inspection intervals).
|AS3873 - 1995|| Pressure Equipment - Operation and Maintenance|
Specifies requirements and owner and contractor responsibilities and gives guidance on operation, maintenance, and operational surveillance and risk assessment of pressure equipment. Reference to this standard is provides for good working practice for tanks.
|API 575-1995|| Inspection of atmospheric and low-pressure storage tanks|
Details reasons for inspection and methods of inspection, methods of repair, record keeping and reporting.
Provides check sheets for in service and out of service inspection.
|API RP 651-1997|| Cathodic Protection of Aboveground Storage Tanks|
Details damage mechanisms and CP requirements
|API 652-1997|| Lining of aboveground petroleum storage tank bottoms|
Details lining selection, cleaning and lining installation procedures.
Makes no reference to post-construction inspection issues.
|API 653-1995||Tank inspection, repair, alteration, and reconstruction|
Details minimum requirements for maintaining integrity of storage tanks, inspection frequency and methods of inspection, methods of repair, alteration, record keeping and reporting.
Provides check sheets for in service and out of service, internal and external inspection and API 620 and 650 code compliance.
Recommends monthly operational external visual, 5 yearly external inspection by authorised inspector, 10 yearly internal inspection with possibility of 20 yearly bottom inspection where corrosion rate has been measured.
|API 2000-1994|| Venting atmospheric and low pressure storage tanks|
|API 2015-1994|| Safe entry and cleaning of petroleum storage tanks|
Details safety precautions and standards of cleaning for inspection.
|API 2021|| Fighting fires in and around flammable and combustable liquid |
atmospheric petroleum storage tanks
|API 2207-1998|| Preparing tank bottoms for hot work|
Details safety precautions for hot work on tank bottoms.
|API 2200||Improving owner and contractor safety performance|
|API 12R1-1997|| Recommended practice for setting, maintenance, inspection, operation, and repair of tanks in production services|
Provides useful guidelines on tank corrosion mechanisms. Provides check sheets for in service and out of service, internal and external inspection.
|API 327-1994|| Aboveground storage tank standards: a tutorial|
Summarises contents of all API standards and provides worked examples for determination of corrosion rate and inspection interval.
|API 334-1996|| A guide to leak detection for above ground storage tanks|
Summarises trials and validation on key 4 techniques.
|NACE RP 0193-1993||External Cathodic Protection of On-Grade Metallic Storage Tank Bottoms|
The primary applicable Australian standards for in-service inspection of tanks are AS1940 and AS3788, which specify requirements for regular operational surveillance and a maximum internal inspection interval of ten years. API 653 is an important additional document that addresses suitability for service and repair and alteration requirements for large, atmospheric pressure above ground, steel storage tanks. API 653 cannot provide a cook book of answers to all issues and therefore should be regarded as outlining a program of minimum requirements for maintaining tank integrity. It outlines best available, cost-effective technology to ensure that leaks or catastrophic failure do not occur.
API 653 departs from most inspection specifications in that it requires an engineering analysis of the inspection data. Thickness measurements are evaluated to ensure that the tank is structurally sound, within allowable stresses for the required design conditions and will not leak before the next inspection. Confirming that a tank will not leak goes beyond ensuring that it will not fail catastrophically, since even a small leak is unacceptable. API 653 emphasises the need for engineering experience when evaluating a tank's suitability for service. It requires that evaluation be conducted by organisations that maintain or have access to engineering and inspection personnel who are technically trained and experienced in tank issues.
API 653 recognises that fabrication and inspection records for older storage tanks may be incomplete and the original degree of inspection and construction material may be unknown. However, it still provides a structural integrity evaluation of such tanks by using conservative assumptions. In these cases, shell thickness calculations use a low weld joint efficiency of 0.7 and assume the use of a relatively low-strength material. This reinforces the benefits of maintaining proper tank design, fabrication and inspection records. The concepts of three-stage life assessment, developed for pressure equipment and outlined in AS3788 Appendix U may be used. If records are inadequate or if damage mechanisms are not understood, the next stage of assessment is used. The information from each stage feeds into the next. Successive stages are more comprehensive and costly: therefore each stage is performed only as required. The data requirements of the three stages of tank assessment are summarised in Table 1.
|Feature||Stage 1||Stage 2||Stage 3|
|History||Anecdotal||Plant Records / Operations log||Review Plant Records|
|Dimensions||Design||Nominal (General Arrangement drawings)||Measured|
|Condition||Records or Nominal||Inspection||Detailed Inspection|
|Contents (fill heights)||Design||Operational||Measured|
|Stresses||Design or Operational||Simple Calculation||Refined Analysis|
|Material Properties||Assumed to be low strength||Specification minima||Heat data|
|Table 1: Suggested data requirements for the multi-staged assessment of tanks.|
MORE RIGOROUS ASSESSMENT
MORE ACCURATE OPERATIONAL DATE REQUIRED
MORE ACCURATE UNDERSTANDING OF CONDITION
An inspection program should address the four main storage tank components: the roof, shell, bottom and foundation. There are several subcategories within these main components, including the tank bottom to shell connection, shell penetrations and roof connections. There are other factors that can affect the life of tanks, including fixed fire fighting systems and floating roof drains. These will not be considered here.
Compliance with API 653 costs time and money. Although compliance with API 653 is not mandatory, such industry standards have always had the standing of " good industry practice" in the view of most regulatory authorities. Compliance with API 653 or a corporate or other equivalent is really an investment, in that the long term costs are likely to be more than recouped, due to avoided costs of site remediation from spills, potential fines and lost business. API 563 may also more directly reduce costs in demonstrating that tanks built to older design standards continue to be fit for service.
Engineering analysis methods are potential alternatives to repairing a problem tank. The decision on which approach to take, repair or analysis, should be made on a case-by-case basis on relative costs and schedule considerations. If using the API 653 shell-thickness calculations based on minimal data does not cause a severe fill-height restriction or mandate extensive repairs, then the additional expense and time required for further analysis may not be justified. However, if the initial inspection and evaluation results show that there is a significant problem then the additional inspection and evaluation may be worthwhile. Thickness "averaging" is possible. With this approach, credit is taken for reinforcement provided by thicker regions that are next to corroded regions of a tank shell. Similar credit may be taken by performing thickness calculations based on specific elevations of corroded regions. This accounts for actual hydrostatic head imposed at the corroded region, rather than making its minimum required thickness equal to that required at the bottom of the particular shell course.
If analysis is required, API 653 provides guidelines for many types of repairs and alterations, including patch plates, alteration of nozzles, bulge repairs, bottom repairs or replacement, roof repairs, floating roof seal repairs, hot taps and repair of defective welds.
Appendix C of API 653 contains comprehensive checklists to perform in-service and out-of-service visual inspections. Some checklist items relate to tank operational factors, such as whether the level control is operational, while other items relate to structural integrity issues. The philosophy of API 653 is to gather data and to perform a thorough initial inspection in order to establish a baseline for each tank inspection against which future inspections may be used to determine rates of corrosion or changes that might affect fitness for service. The scope of inspection is always subject to interpretation: for instance, a cursory or limited inspection may miss the one pit in the floor that can lead to a leak. To inspect for floor top-side corrosion, it is essential that the floor is cleaned by grit blasting. While expensive (several tens of thousands of dollars for a crude tank), it has proven to be the only sure way of uncovering defects. It is usually found that tank integrity assurance costs are dominated by cleaning / sludge removal activities prior to inspection and application of confined space entry precautions, rather than by inspection costs.
Few alternatives are available to inspect the tank bottom for underside corrosion. Commercially available inspection techniques include those based on magnetic-flux exclusion (MFE) and automated ultrasonics. Both inspection techniques require that the floor is dry and free of dirt, sediment and corrosion products[Z You and D Bauer. Materials Evaluation. July 1994, pp 816 - 818. V52. Combining eddy current and magnetic flux leakage for tank floor inspection] . A recommended minimum inspection would be a MFE inspection of all floor plates with ultrasonic follow-up of suspect areas, vacuum-box testing of floor-plate welds and dry magnetic particle or liquid penetrant inspection of the shell-to-bottom weld. Again, future general corrosion and pitting rates, both topside and underside, need to be estimated to evaluate the acceptability of the current bottom thickness. It may be useful to cut out coupons from the floor for visual inspection of the underside, and to allow cathodic protection potential to be confirmed at different distances from the periphery to the centre of the tank. API653 does not explicitly state how many thickness measurement points must be used in each shell course or plate. If the tank interior is accessible for visual examination, a minimum number of measurements should establish nominal thicknesses and additional inspection of localised corroded areas will provide corrosion rate data. The required future corrosion allowance is then estimated, to ensure that the shell will not thin below the minimum acceptable level before the next inspection.
There are a number of techniques which offers the possibility of on line inspection of large API tanks such as volumetric or mass methods, acoustic emission (AE), soil vapour monitoring and inventory control. Extensive development, trialing and validation has been undertaken by API. Table 2 summarises the characteristics of these four leak detection methods.
|Volumetric||Acoustic Emission||Soil vapour monitoring||Inventory control|
Santos QNTBU operate approximately 450 tanks over a vast area: for example, petroleum leases in south west Queensland are larger than some European countries. Operation involves a wide variety of tanks, such as static and movable storage tanks (wash, production, well fracture stimulation), API 620 and 650 tanks, water tanks (potable, fire, secondary settlement or separation), underground storage tanks and diesel fuel dispensing tanks (eg. for oil pump engines). Over half of the tanks have been in service more than 15 years. Typical tanks are shown in Figures 1 and 2.
|Fig 1: Typical Santos owned API 650 tank, at Lytton. Some CALTEX tanks in the background||Fig 2: Typical Santos owned field production tank.|
Santos is enhancing its management systems for the integrity assurance of equipment, including tanks. The tank integrity assurance program has compiled a database of tanks detailing tank location, size, commissioning date, redundancy and many other details. Inspection schedules for assessment of external and internal condition (using conventional techniques and AE) are being refined, as are procedures for record keeping and in-service monthly inspections. After establishing corrosion rates, inspection intervals based on risk are determined and inspection programs implemented.
In the risk assessments that are performed, the probability of tank failure is based on: -
In the risk assessments that are performed, the consequences of failure are based on: -
As an example of the detail involved in the risk assessment a factor is used to consider the various contents of tanks: mixtures of oil and water are more corrosive than water, which are in turn more corrosive than crude. The water cut is taken as an indicator of corrosion likelihood. A threshold of 30% is used, below which corrosion is considered unlikely.
The overall evaluation of plant risk is a product of the probability and consequence of failure. When this risk factor has been determined it is possible to categorise and rate tanks with regard to their potential impact on operation. Risk assessment data is shown in Figure 3. Note the logarithmic Y-axis. It is apparent that risk is dominated by a limited number of tanks. This result is typical of the risk profile generated by risk based inspection assessments, where a Pareto principle of 80% of the risk resulting from 20% of the equipment is generally found.
Fig 3: Santos tank asset management program, output from relative risk ranking of tanks by business area. Ranking refers to the position on a list of tanks sorted in order of highest risk to lowest risk.
Note Y axis is logarithmic
Tankage includes crude oil tanks, which typically may contain 40 million litres, intermediate-product and end-product tanks that may be a tenth that size, and tanks for ancillary storage (such as condensate, caustic, and other components that assist the refinery operation) which are typically about a tenth of that size again. Construction can be floating roof, cone roof, cone roof with internal floating roof, and cone up or cone down floor. While often regarded as static equipment, they are in fact the only examples of refinery equipment that are routinely stressed to their full design value and this occurs cyclically.
Contents can be at any temperature from ambient to well over 100°C, and can be quite hazardous: the 'lead' additive for leaded petrol, Tetra-ethyl lead, is a highly toxic compound which also brings with it particular corrosion issues. Although now phased out at this refinery the tanks and ancillary equipment are still to be disposed of, and it is probable that product tanks that have contained traces of the compound will always have to be treated as if the compound is still present.
The biggest life management issue is corrosion of floor plates. Corrosion from under the floor strikes randomly; tanks badly affected may be situated next to tanks which are not affected. It is assumed that this is caused by variations in the nature of the fill under the tanks, which was pumped up from the river bed during construction of the refinery. Experience is that, with cone-up tanks, the outer 6 metres of the tank floor is susceptible (occasionally 8 metres). The tanks were originally constructed with 1/4 inch (6mm) floor plate with no annular ring: replacements incorporate a 10 mm thick annular ring. Cathodic protection can help but does not provide a complete answer, as soil conditions can be very difficult and small portions of the floor may be 'shielded' from the CP current. Internal corrosion, on the floor top face, is caused by bacteria or from acid or other contamination of product. Defects can be general or local pitting in plates or welds. Cracking has rarely been found.
Coating the floor with glass fibre reinforced resins was common in the 1970s and 1980s but is no longer practised. It had been thought that this would bridge across corrosion pits that continue to grow and perforate the plate after the lining is applied but there has been a failure and the lining made the leak very hard to locate. Furthermore there is a fear that this may mask a potential problem until sudden rapid failure occurs. Reinforced resins can also make ultrasonic inspection of the floor plate difficult or impossible, although magnetic flux leakage devices will perform well through such a coating. Applying a suitable paint coating will give good protection to the top surface of the floor, while still allowing ultrasonic inspection of the plate and better assurance as to whether any thinning found is from the top or bottom surface of the plate.
A further issue with tank floors is with the small area of floor plate that protrudes beyond the tank shell, known as the 'chime'. Where there is no annular ring, the joins between sections of the chime are made with a joggled joint, which is fillet welded. As the tank fills the chime is stressed in tension and we have seen cracking in the fillet welds, with a tendency for this to be worse where the joint is orientated radially. Several attempts have been made to calculate stresses in this area with no conclusive result. There have been no failures but occasionally cracks have been found propagated into the floor to shell weld. The chime is also subject to severe corrosion from underneath but, for some unexplained reason, this does not appear to progress under the tank shell unless it is coincident with corrosion occurring further in.
The shells of some product tanks have corroded internally, particularly with floating roof tanks in leaded petrol service. The lead additive contained bromide and chloride compounds, which broke down in sunlight to form hydrobromic or hydrochloric acid. This caused deep pitting of the shell where the wall is repeatedly wetted as the level changes. Replacing tank strakes was only a temporary solution, and initial attempts at painting failed quickly. An assessment of procedures and inspection of failed coatings suggested that much of the problem lay in not properly curing before filling the tank. Coupled with a program devised to select suitable coatings this has lead to a very successful solution to the problem, and no strake replacements have been made in over ten years despite many tanks being painted when shells had already corroded to the minimum allowable thickness.
Floating roofs have particular integrity issues. External corrosion can occur where water and blown-in dirt collects, around the roof drain sump and where attachments are welded to the roof. Particular attention to details of design, inspection and painting are required to manage this. Floating roof leg and leg sleeves corrode in the vapour zone, and close inspection is required before a tank is taken out of service to ensure the safety of maintenance operations inside the tank. Similarly the sides of pontoons corrode severely in the vapour zone. This area, despite the difficulty of access, must be inspected and painted. Volatile components can create vapour bubbles under the roof which can cause the roof to tilt, and possibly to sink. Venting the high point adjacent to the pontoon at several places around the tank will prevent this. Floating roofs are constructed of lap welded plate. Corrosion can occur in the lap between the plates. Experience indicates that this always occurs only on the bottom plate and taking sections has never revealed any corrosion attack on the weld zone. Interestingly, this effect has never been seen on floor plates. Lapped plates can also give rise to problems when other components are welded through a lap and it can be very difficult to seal all leak paths. With large tanks, wind action is said to cause the roof to 'ripple' giving rise to fatigue cracking in lap joints but this has never been experienced at the refinery.
External corrosion can also occur on insulated tanks, which tend to operate at optimum temperatures for corrosion. Attempts at performing global inspections without removing insulation, for example using thermography, have not been successful and stripping areas for inspection has been the only successful method found. Techniques available for inspecting pipe for corrosion under insulation are not generally applicable to tanks.
The general description of tanks within BP Bulwer Island also applies to Caltex Lytton, with the exception that all Lytton tanks have been constructed with cone up floors.
The biggest life management issue is the limited access for cleaning and inspection imposed by the shortage of tanks and the lack of flexibility that this imposes. Tanks have traditionally been taken out of service for major inspections at fixed ten year intervals. As with the BP Bulwer Island tank farm, the Caltex Lytton tank farm was constructed on reclaimed land. This has been an advantage to Lytton because it gives a conductive soil which gives good distribution of the cathodic protection currents. The tank farm is electrically continuous, the cathodic protection anode beds are distributed around the tank farm at convenient locations and are powered by very reliable robust transformer/rectifiers. Earlier tanks were constructed on oil sand, and later tanks on bitumen soaked boards. The combination of sound construction practices and good cathodic protection has meant that underfloor corrosion has never been a problem at Lytton and maintenance attention can be directed to controlling internal corrosion from the crude and products.
Lytton has recently developed an Alliance with Saunders to cover tank inspection and maintenance. Saunders provide a tank manager on site, a Saunders tank inspector and a Saunders maintenance workforce. Budgeting is prepared by Saunders and approved by Caltex. The Alliance works on risk/reward principles based upon key performance indicators that are still evolving. The Alliance developed a risk hierarchy of all AS1692 Category 6 tanks, which has initially been used to prioritise the external in-service inspections. The intention is that in the future it will be used as the basis to set intervals on a risk based inspection basis as allowed by API 653, although the regulatory authority must first approve this change. The risk matrix is a 6 x d6 type, with the likelihood of failure being determined by looking at the floor, shell and roof in terms of the current inspection and anticipated deterioration rate and the consequences of failure being determined by environmental issues, safety issues, and production criticality.
Crude tank floors are painted, and the coating extends a metre up the walls. Fibreglass floor coatings are still in service and have performed well because under-floor corrosion is almost non-existent but, as at BP Bulwer Island, there is a recent preference towards paints because they allow inspection of the steel thickness beneath using modern inspection methods. Although magnetic flux exclusion examination of a crude tank floor has been tried, the results were disappointing and of little value. Nevertheless, there is interest in using techniques such as magnetic flux exclusion to better assess floor condition in the future.
Gasoline tanks are painted to control corrosion and avtur tanks are painted for product cleanliness reasons. Increasingly, there will be a tendency to paint other tanks in accordance with the aim to increase the duration between major out of service inspections.
There is reluctance in the inspection community to accept new technology at face value. There have been too many disappointments when new devices have been oversold and, in the case of new technology for tank inspections, even demonstrations can be expensive.
The development of magnetic flux leakage equipment for under-floor inspection has made a major impact on tank inspection and subsequent reliability but this still requires the tank to be taken out of service and cleaned. Confidence in the technique, using suitably skilled operators, is high. Current developments in floor inspection techniques include remote operated vehicles that can be inserted into tanks while filled with product and perform an ultrasound inspection of the floor plate. This is limited to tanks which have only a light deposit on the floor and certainly would not be expected to succeed on crude tanks that can have two metres of heavy sludge. A method for performing such an inspection while the tank is in use unquestionably constitutes the 'Holy Grail' of tank inspections.
Acoustic emission (AE) has been developed to a sophisticated level [RK Miller. Mat. Eval. 6, 1990. Pp 822 - 829. Tank bottom leak detection in AST by using AE], [CM Nickolaus. Mat. Eval., 1988. Pp 508 - 512. AE monitoring of ASTs. ], [R Nordstrom. Mat. Eval. 48, 2,. 1990. Pp251 - 254. Direct tank bottom leak monitoring with AE.], [EG Eckert, MR Fierro and M Maresca. Materials Eval. Aug 1994. V52. Pp 954 - 958. The AE noise environment associated with leak detection in ASTs] though is primarily a maintenance sorting tool. It has been used successfully by a number of large oil and gas companies and is offered commercially by two Australian companies and under licence by other Australian companies. However, AE testing has shown mixed results, and detection of underfloor leakage on operating tanks has given some disappointing results. It had been hoped that a leak would produce a signal that could be located with the tank on-line but results did not bear this out. On one occasion, a loose sample bottle on the tank floor was blamed for giving spurious signals (though how this would occur with the tank 'stilled' for a day or so is not clear) but usually no feature has been found to explain a false indication. It is currently thought that the signals produced by the corrosion reaction itself may be detected, and interest now lies in using this to assist in ranking tanks for inspection based on detection of corrosion activity rather than leakage. Therefore AE is not the 'Holy Grail' as it does not give an idea of the structural condition of the floor. A leak can be from many causes and the mere act of corrosion may have different implications. The current development of remotely operated vehicles (ROV's) to inspect on-line may bring this a step closer, bringing an array of inspection techniques onto the tank floor. In the case of ultrasonics, coupling a probe to the plate would be a simple matter (as has been proven by manual use in water tanks) and in principle many other techniques could be applied. However a tank can be a very large structure - 60 metre diameter tanks are common - and a full survey over the floor of such a tank would be time consuming and expensive.
All this assumes that any leak is from in-service deterioration, but there is much anecdotal evidence of leaks from new construction, through weld defects or even missing welds. Vacuum testing of floor welds is a physically demanding task and depends on great operator diligence for success. Sensitive leak testing, injecting helium under the floor and detecting its emergence into the tank has been tried with mixed results. It has been known for tanks to be put in service with large sections of the inside floor to shell weld missing and on one occasion comparatively minor corrosion in the external weld opened up some gas pores which resulted in a leak. A small length of inner weld had been omitted some distance away and the tank contents were able to track round between the two fillet welds that constituted the floor to shell joint.
In repairing tanks, replacement of floor plate is achieved by oxy-cutting the floor-shell weld and welding in the new floor in the same location. The effect of repeating this several times over the life of a tank is largely unknown. The Welding Institute advises against welding in the same location more than twice, yet floor replacements are made more often than this. Cutting out a section of shell to move the weld location reduce the tank volume significantly, for example on a crude tank removing 10 mm would reduce the volume by about 30,000 litres.
The issue of hydrotesting is also of interest. With pressure vessels, hydrotesting is performed at a pressure significantly above the design. The API codes (650 and 653), however, require hydrotest stresses to be calculated and have far lower allowable stress ratios (test to design). In view of the fact that testing can only be performed under a head of water equal to the tank height, and would only give 125% stress for a tank designed for product of SG 0.8, the code seems to be making an unnecessary complication. In fact, while the benefits of overstress under controlled conditions are well documented, these codes seem to work to ensure that such benefit is avoided. If the prospect of brittle fracture with a tank filled with icy water drove these requirements the codes should say so but, in any case, this issue is in need of clarification. A warm proof test may well have prevented the Pennsylvania event referred to above. The reference below['Stress: are you giving enough?', RR Griffiths, Australian Welding Journal Vol 43, 3Q 1998, 'Controversy Corner' article.)] gives more detail of issues with tank hydrotesting.
Degradation of tanks is generally slow and failures are infrequent: indeed, many tank inspections detect no defects and minimal change in condition. While there have been incidents, some quite spectacular, there have fortunately been no tank incidents that have had an impact on the local community of 'Flixborough' or 'Bhopal' proportions. The Pennsylvania incident referred to above had a major impact on the local river systems, as mentioned, but this was an unusual case involving a re-constructed tank. It is suggested that some, perhaps most, of the major incidents that have occurred have been a result of less than adequate engineering or inspection rather than due to poor standards and that, in the past, inspection performed with limited means and to the best of the inspector's ability reduced the impact of events, to just a floor leak, for example. This leads to the question of how much can the interval between inspections be extended without increasing risk.
Risk assessment of tanks provides a powerful approach for optimising inspection and refurbishment strategies. Risk assessment combines both the probability and consequences of failure to establish a prioritised list of plant. This allows the tank owner to allocate resources to high risk plant and minimise activities that are not doing an effective job of reducing risk. The scope and timing of turnarounds and inspections can be optimised while reducing safety and environmental risk to an acceptable level. Risk based inspection techniques have been successfully applied to tanks[JT Renyolds. Inspectioneering Journal. March / April 2000. RBI of ASTs]. Improvements in inspection techniques and technology will further reduce the incidence of minor events. The changing importance of environmental considerations make this essential. The time is right for application of risk based and risks directed inspection techniques and the use of established three stage life assessment methods of tanks.
Tanks can pose hazards to the community, the environment and to operating companies because of the large inventory of materials and the criticality to the operation. These hazards are often overlooked. There is considerable guidance available on tank inspection and integrity. This paper catalogues and discusses references, such as API653, and techniques, such as acoustic emission.
A number of case studies are presented which describe a variety of issues that need to be considered when developing tank integrity management programs. Risk based and risk directed inspection techniques and the use of established three stage life assessment offer potential for establishing adequate, cost effective programs.
The authors are grateful to their colleagues for assistance in managing tank integrity programs. The content of this paper should not be taken as necessarily reflecting policies or obligations of the associated companies and is presented to convey the views and experience of the authors.
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