September 2016

Maintenance and Reliability

Design operations-and-maintenance-friendly pressure vessels—Part 2

In Part 1 of this article, the assistance provided by standardizations to gain improved vessel performance—vessel outer diameter (OD), component metallurgies, manways and saddles—was discussed.

Murti, D. G., The Augustus Group

In Part 1 of this article, the assistance provided by standardizations to gain improved vessel performance—vessel outer diameter (OD), component metallurgies, manways and saddles—was discussed. This work will explore other features that can supplement vessel design and improve operations and profitability.

Note: Readers are advised to make their own engineering judgments on the validity of the design improvements suggested here, and to develop their own conclusions.

Throughout this article, the terminology “vessel” is used to represent pressure vessels, drums, columns, towers, heat exchanger shells and any equipment designed using pressure vessel codes, such as ASME-VIII, EN 13445, PD 5500, etc. The terms “codes, standards, specifications, regulations and recommended practices” are used to broadly define the overall prevailing industry design requirements, recommendations and practices.

Avoid fireproofing and flanged joints inside the skirt

Many company specifications ask for fireproofing inside the vessel skirt due to the presence of flanged joints. These features create problems for field maintenance. Corrosion under insulation (CUI) and corrosion under fireproofing (CUF) have assumed greater importance and have been known to cause equipment collapses. API’s first publication in 2014, API-RP-583, “Corrosion under insulation and fireproofing,” underscores the importance of tackling this problem (FIGS. 1A and 1B).

Fig. 1A. Avoid a flanged joint and fireproofing inside a vessel skirt.
Fig. 1A. Avoid a flanged joint and fireproofing inside a vessel skirt.
Fig. 1B. A typical drawing asking for fireproofing inside a vessel skirt.
Fig. 1B. A typical drawing asking for fireproofing inside a vessel skirt.

Table 2 of API-583, “Locations for corrosion under insulation and fireproofing,” clearly identifies the insulated zone at the skirt weld and fireproofed skirts as areas to be watched for accelerated corrosion and leaks. API Standard 2510, “Design and construction of LPG installations: Section 10.8.4,” states, “When a vertical vessel is supported by a skirt, the exterior of the skirt shall be fireproofed.” This implies that even for highly flammable services like liquefied petroleum gas (LPG), the interior of the skirt need not be fireproofed.

It is recommended to cover large skirt openings with a vented removable cover, preventing plant site waste materials from accumulating inside. Typical site waste materials include plastic bags, pieces of fireproofing/insulation pads, pieces of gaskets, etc. Stray animals have been known to occupy unattended vessels with large skirt openings. The practice of storing small tools and consumables inside vessel skirts should be discouraged from a safety perspective—keeping skirt openings closed is the best option.

Code supports covering skirt openings

API 2510A, Section 5.8.2.2, “Fire protection considerations for the design and operation of LPG storage facilities,” states, “The interior should be fireproofed if there is more than one access opening in the skirt that is not covered with a plate.” The section implies that fireproofing is not required if skirt openings are minimal and covered. The code indirectly infers that if there is only one opening, it may be left open. However, this should be discouraged. Skirts should always be gas-tested before manual entry.

Fig. 2. The drain nozzle was enlarged to 4-in. (100-mm) NPS, the recommended minimum regardless of what a computer program dictates.
Fig. 2. The drain nozzle was enlarged to 4-in. (100-mm) NPS, the recommended minimum regardless of what a computer program dictates.

Adequate sizing of vessel’s process nozzle at bottom

Always ensure that the bottom process nozzle is large enough. The recommended minimum is 4-in. nominal pipe size (NPS), regardless of what a computer program dictates. Small nozzles eventually clog, particularly in the upstream industry, even if the fluid is classified as “clean” on data sheets. FIG. 2 shows a typical vessel where the bottom nozzle was enlarged to 4-in. NPS as a last-minute change. The rest of the piping was left as 2-in. NPS, to be replaced later. Any hot work to a vessel is a herculean task and very difficult for operating plants, but piping changes are comparatively easy and can be accomplished in a routine plant shutdown.

Some engineers prefer a flanged joint inside the skirt due to a reasonable concern that the replacement of an elbow (subject to corrosion and high-velocity erosion) would prove to be a more difficult task. However, experience with large nozzles and elbows with reduced velocity has proved to be satisfactory.

Adequately sized gravity drain nozzle

All vessels that undergo maintenance must be hydrotested and completely drained of water. The potential drainage time for large vessels is an issue in delaying plant startups. Some large vessels take 24 hr–48 hr for a gravity drain. Most company specifications/data sheets do not specify a maximum drainage time under gravity flow. It is recommended to restrict drainage time to 3 hr–4 hr. This information is rarely found on vessel drawings or data sheets, and it is vital for planning of other maintenance activities in tandem.

Literature is available to estimate drainage time under gravity for horizontal and vertical vessels and spheres, and to account for pressure loss in drain piping.1,2

Reinforcement plate for 150# flanged opening

Code calculations do not dictate reinforcement pads for small-diameter openings, particularly for low-design pressure vessels. Reinforcing pads may not be needed for small-diameter openings, even in high-pressure vessels. A practical example of a water-seal drum is illustrated in FIG. 3A. The bottom drain nozzle is 6-in. (150-mm) NPS and welded directly to the vessel without a reinforcing pad, as dictated by the code calculation. Water and a hydrocarbon mixture accumulated inside a skirt, as shown in FIG. 3A, and a leak path shown in FIG. 3C. As the skirt opening was covered, no dirt was accumulated, reducing the fire hazard and enabling easy cleaning.

Such vessels are difficult to repair when leaks develop through the nozzle weld. As there is usually no available time to make the vessel gas-free and carry out the time-consuming hot work, some technicians use proprietary cementitious materials for sealing the leaks, as shown in FIG. 3B. This shortcut is not recommended.

It is recommended to provide reinforcement pads for bottom nozzles, thereby superseding code calculations (FIGS. 3C and 3D). Advantages include:

  1. Reinforcement pad provides secondary protection from leaks
  2. Leaks can be detected at early stages from “tell-tale” hole
  3. Hot work can be carried out from the outside using low-heat electrodes, without the need to make the vessel gas-free
  4. If leakage is a persistent problem, a pressure gauge can be installed for early warning, as shown in Fig. 3E.
Fig. 3A. Bottom drain connection without a reinforcement pad, which may not be needed for small-diameter openings, even in high-pressure vessels.
Fig. 3A. Bottom drain connection without a reinforcement pad, which may not be needed for small-diameter openings, even in high-pressure vessels.

Fig. 3B. Leak repaired using cementitious material, a shortcut that is taken when there is no time available to make the vessel gas-free or carry out the time-consuming hot work.
Fig. 3B. Leak repaired using cementitious material, a shortcut that is taken when there is no time available to make the vessel gas-free or carry out the time-consuming hot work.
    Fig. 3C. Not recommended.
    Fig. 3C. Not recommended.

    Fig. 3D. Recommended #1.
    Fig. 3D. Recommended #1.

    Fig. 3E. Recommended #2 for sour and toxic service.
    Fig. 3E. Recommended #2 for sour and toxic service.

    Vessel relief valve fitted with demister pads

    Relief valves on columns and towers were previously installed downstream of demister pads. Accidents have been reported where, due to process upsets, the demister pad disintegrated and choked the relief valve inlet. Now, codes require that relief valves remain in an unobstructed path (FIG. 4), which means upstream of the demister pads, if any. This recommendation has been subsequently clarified under the ASME-VIII chapter, “Best practices for the installation of pressure relief devices.”

    FIG. 4. Codes require that relief valves remain in an unobstructed path. This rule has been subsequently clarified under ASME-VIII.
    FIG. 4. Codes require that relief valves remain in an unobstructed path. This rule has been subsequently clarified under ASME-VIII.

    Although this recommendation is not retro-effective, it should be possible to modify non-complying vessels by relocating relief valves on the side inspection openings available on most vertical vessels. If installed upstream, the relief valve size must be reconfirmed due to possible liquid carryover to the relief valve. If valves are installed sideways and discharge in the open, then care should be taken to strengthen the side nozzle per API-520, Part 2, Section 4.4.1. Recalculating noise at grade per API 521, Section 5.8.10.3 is appropriate due to the slightly higher noise level at grade caused by the lower elevation of the relief valve. A vessel nozzle that is one size larger than the relief valve nozzle is preferred for possible future upsizing of the relief valve. Using a reducing elbow is preferred from a stress and lower pressure-drop point of view, as compared to a standard elbow and a reducer combination.

    Avoid internal ladder in corrosive service

    Internal ladders installed in vertical vessels in corrosive service and in vessels packed with internals serve little purpose. Such ladder rungs create safety hazards and obstruct installation of scaffolding for maintenance works. FIG. 5A shows lower ladder rungs that have corroded and fallen apart, which could be attributed to a higher concentration of corrosive fluid in the lower stagnant portion of the column.

    The integrity of such ladders, including the rungs, is doubtful. Ladder rungs are made from ¾-in. (20-mm) bars and welded to the vessel wall, sometimes with poor workmanship. Due to corrosive media degradation, the welding is insufficient to sustain a human load. The wear plate design is also questionable (FIG. 5B). Typical wear plates require ¼-in. (6-mm) tell-tale holes to ensure porosity-free welding. The tell-tale hole provided from a good welding aspect only assists corrosive fluid to enter the cavity and expedites the detachment of the wear plate from the vessel wall. What began as a good intention from the design phase could potentially prove fatal for field personnel.

    Fig. 5A. Vertical vessel with corroded internal ladder rungs.
    Fig. 5A. Vertical vessel with corroded internal ladder rungs.
    Fig. 5B. Ladder installation details.
    Fig. 5B. Ladder installation details.

    In this particular case, due to severe corrosion, the ladder rungs were removed and the area ground flushed and painted. An aluminum ladder lowered from the manway proved to be a good temporary substitute.

    Nozzle openings through welded seams

    It is a general impression that opening through welded seams is not permitted by codes. Such openings are often detected only in the late stages of vessel design, when the plate-cutting diagrams have been prepared. An owner’s design engineers are not involved in the review of plate-cutting diagrams, and (at this stage) the vessel general arrangement (GA) and piping GA/isometric drawings are already frozen. To avoid openings on welded joints, nozzles are relocated and related piping is rerouted. This exercise is expensive, time-consuming and unnecessary.

    ASME-VIII, Div. 1, UW-14, “Openings in or adjacent to welds,” permits this practice, as does ASME-VIII, Div. 2. The overlap of reinforcement pads of adjacent openings is also permitted. FIG. 6 shows a Div. 2 vessel with a manway located on a circumferential seam weld. The vessel has been in intermittent service for the past 39 years without any leaks.

    Fig. 6. Nozzle opening through circumferential weld seam.
    Fig. 6. Nozzle opening through circumferential weld seam.

    Proper relief valve nozzle sizing

    A vessel relief valve opening one size larger than the relief valve inlet nozzle is recommended (FIG. 4). A reducing elbow design in lieu of a standard elbow and reducer is preferred and helps field personnel avoid hot work in case a larger relief valve is needed in the future. Vessels have a long life expectancy among major process equipment, and should manage increased gas flowrates in aging production fields.

    Separate as-built drawings for each vessel

    Some vessel manufacturers provide only one set of as-built drawings if multiple identical vessels are ordered. For two identical vessels, V-101A and V-101B, these manufacturers will provide only one set of as-built drawings tagged as V-101A/B. The mantra, “All work is completed by computer numerical control (CNC) machines, so all vessels are identical,” is a paperwork-saving shortcut approach that does not help the end user. At times, only one vessel may be modified in the field, so one set of as-built drawings for each tagged vessel (V-101A and V-101B) are vital. Third-party inspectors should ensure compliance and insist on signing off on each set separately. This requirement is applicable only for as-built drawings. During design stages, only one set of GAs should be provided tagged as V-101A/B.

    Transportation and storage notes

    While part of an operating company’s technical support team, the author was asked for a particular grade of mineral oil. It was discovered that the oil was requisitioned to apply on the inside surface of a vessel before it was put back into operation. Further questioning revealed that the vessel GA drawing included the comment, “Mineral oil, grade xxxx, is to be applied inside the vessel.” The mineral oil coating was meant for new vessels as a rust preventive during transportation and prolonged storage. The technicians had unknowingly been following the procedure for vessel maintenance.

    The lesson is that transportation notes should not be appended on vessel GA drawings. If appended, the purpose of such notes should be clearly stated to avoid confusion, keeping in mind that maintenance personnel faithfully adhere to all instructions stated on vessel GA drawings. The impression that the role of vessel GA drawings ends once a vessel is commissioned is incorrect. GA drawings are a valuable maintenance aid and necessary throughout the life of a vessel. Providing a set of A-3-size GA drawings and internals, no matter how congested the reduced-size copies look, is suggested. Jumbo-size drawings (A-0, A-1) are difficult to handle in the field; photocopiers are rarely available to make copies of A-0 and A-1, and such drawings usually end up in untraceable custody, albeit with good intentions.

    State vessel operating weight

    General protocol dictates that vessel GA drawings provide a vessel empty weight and a hydrotest weight simulating a vessel that is full of water. The transporter must know the empty weight. The hydrotest weight is required by the vessel manufacturer to ensure that the shop floor can handle the load, and it is also used to design the vessel foundation onsite. This works well if the fluid is water or lighter than water.

    What happens if the vessel is designed for fluids heavier than water—e.g., sulfuric acid (specific gravity = 1.84)? The fluid weight would almost double, but the GA drawing may still state the hydrotest weight. Cases have been reported where the hydrotest weight from a GA drawing was inadvertently used to design a civil foundation for sulfuric acid vessels, resulting in undue foundation settlements. Specifying a vessel weight as full of liquid for heavier fluids, in addition to usual empty steel weight and hydrotest weight, would be a good practice.

    Recertification after repairs

    Old vessels sometimes require new nozzles when moved and pressed into another service (FIG. 6). New nozzles were added to this 155-t separator vessel. Built in 1977 to ASME Div. 2 standard, the vessel did not have readily available design calculations nor National Board (NB) registration. Nevertheless, the additional nozzles were added and the vessel recertified to Div. 2. The recertification process is not discussed here. The intent is to inform the vessel owners that it is possible to regularize the redundant fit-for-service vessels and recreate the vessel “birth certificate,” or “U” certificate. This defies a prevailing notion that an ASME “R” certification cannot be accorded unless an ASME “U” is produced. A redundant fit-for-service vessel need not be discarded for want of repair modifications and missing documentation.

    Multiple certification

    While oil and gas wells may go dry, a pressure vessel can survive and move to another location. This movement (e.g., state to state) may require different pressure vessel regulations. For this reason, some owners request multiple certifications, which should not pose problems if handled at the design stage. Challenges arise if a vessel is certified for only one state and must subsequently be recertified for use in another. It is advised that design engineers ask vessel end users whether multiple certifications are needed. In this instance, it is better to pay a little extra at the design stage and save undue paperwork, delays and associated expenses later.

    The remaining strength of corroded vessels

    Despite the existence of ASME B31G, “Manual for determining the remaining strength of corroded pipelines,” since early 1980, there was no such document for pressure vessels. The author’s query to ASME in the 1990s received the following response: “The committee has no plans to develop code criteria providing guidelines for calculating the remaining strength of corroded vessels originally fabricated to the ASME code.” In the absence of guidelines, there was a disconcerting practice to treat a vessel as a large-diameter pipe and apply ASME 31G to calculate the remaining strength of corroded vessels. This approach was erroneous and should not have been used.

    Realizing the growing demand for the fitness evaluation of aging vessels, API came out with RP 579, “Recommended practice for fitness-for-service,” in 2000. Not wanting to be left behind this time, ASME joined in collaboration, and a massive (1,128-page) second edition was published in 2007 as API 579-1/ASME FFS-1. The edition’s status was elevated to a “Standard” from the earlier “Recommended Practice.” To illustrate the complex calculations used in the assessment procedures of 579-1/FFS-1, API issued an example manual, 579-2/FFS-2, titled, “Fitness-for-service example problem manual,” in 2009, a very informative 374-page document. It is recommended that practicing engineers consistently reference the example manual to avoid potential errors and conclude the fitness evaluation of corroded vessels with a high degree of accuracy and confidence.

    Summary of cost implications

    While a majority of items will reduce vessel ownership costs, some items may slightly increase the initial cost (e.g., reinforcing pads and larger size nozzles for relief valves and vessel bottom outlets).

    However, project costs (CAPEX) should not be evaluated alone. If the costs incurred by the plant maintenance personnel in maintenance and possible field modifications (OPEX) are added, then all of the suggested measures eventually reduce the ownership cost of the vessel. Traditionally, the OPEX for static equipment, such as a pressure vessel, has been considered to be very low as compared to CAPEX. This is not true. An undersized gravity drain alone can repeatedly make OPEX much higher than CAPEX by way of lost production year after year.

    End of series

    Part 1 of this article appeared in August. HP

    LITERATURE CITED

    1 Kossik, J., “Draining time for unpumped tanks,” Chemical Engineering, Vol. 107, No. 6, June 2000.

    2 Loiacono, N. J., “Time to drain a tank with piping,” Chemical Engineering, Vol. 94, No. 11, August 1987.

    The Author

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