Pressure Relief Valve Inspection Interval

Pressure Relief Valve Inspection Interval Thiago Trotta, Charles Kashou, and Nancy Faulk Siemens Energy, Inc, 4615 Southwest Fwy, Suite 900, Houston, TX 77027; nancy.faulk@siemens.com (for correspondence) Published online 20 April 2017 in Wiley Online Library (wileyonlinelibrary.com). DOI 10.1002/prs.11892 Determining the correct interval for pressure relief valve inspection, testing, and maintenance remains a major challenge for facilities covered by the U.S. Occupational Safety and Health Administration Process Safety Management Standard. To this end, guidance is provided by API Standard 510, Pressure Vessel Inspection Code: In-Service Inspection, Rating, Repair, and Alteration, by API Recommended Practice 576, Inspection of Pressure-relieving Devices, by API Standard 520, Sizing, Selection, and Installation of Pressure- Relieving Devices, Part II-Installation, and by NB-23, National Board Inspection Code Part 2 Inspection. Furthermore, ASME BPVC, Sections I and VIII, provide general guidelines for the repair of pressure relief valves. However, the testing and inspection interval listed, up to ten years, is the maximum time span between shop inspections and overhaul. Further direction is often requested for determining the proper interval for valves in typical process services, especially in cases of PRV chattering. Recent API STD 520 Part II guidance on performing engineering analyses for PRV installations, based on service and specific installation, is included here. In this paper, a decision-making approach to determining these intervals based on a combined understanding of risk-based inspection, quality assurance, engineering analyses, and facility experience is presented. The approach provides process operators and managers with additional assistance in making this determination. VC 2017 American Institute of Chemical Engineers Process Saf Prog 37: 37 41, 2018 Keywords: PRV inspection interval; PRV maintenance; PRV risk-based inspection INTRODUCTION Pressure-relieving devices (PRD) are installed on pressure vessels and boilers in order to relieve excess pressure which may result from the overpressure causes described in the American Petroleum Institute Standard 521 (API STD 521) [1]. These include process upsets, operator error, external fires, and other scenarios. Failure to function properly on demand could result in vessel overpressure, and possibly loss of containment with subsequent explosions, fires, or toxicity impacts. There are also consequences associated with leakage of PRDs. To ensure personnel safety as well as protection of equipment, facilities and the environment, it is essential that the PRD be properly designed, installed, inspected regularly, and maintained in good operating condition. Inspections are used to determine the general physical and operating conditions of the PRD, and assess whether it meets the requirements for a given installation and service. These inspections are of two types: visual on-stream VC 2017 American Institute of Chemical Engineers inspections or shop inspection and overhaul. How often should these inspections take place? Determining the correct interval for a pressure relief valve (PRV, which is a type of PRD) inspection and testing, as well as any indicated maintenance, remains a major challenge for facilities covered by the U.S. Occupational Safety and Health Administration (OSHA) Process Safety Management (PSM) Standard [2] or by similar regulatory requirements. To this end, guidance is provided by API Standards 510 and 520 Part II, as well as API RP 576 and the National Board Inspection Code Part 2 [3] [6]. Furthermore, ASME BPVC, Sections VIII and I, provide general guidelines for the repair of pressure relief valves [7,8]. Note that a definite time interval between inspections or tests should be established for every PRV on operating equipment. Guidance is often requested for determining the proper interval for valves in typical process services, especially in cases of pressure relief valve instability. This paper first describes the instabilities which may affect PRV performance and their causes, then describes how the inspection interval may be determined based on risk-based inspections as well as additional engineering analysis. INSTABILITY PHENOMENA AND CAUSES The principal reason for inspecting and maintaining PRVs is to ensure that they can provide overpressure protection when needed. Inspections determine the condition of the valve and look for signs of damage or other concerns. In addition to corrosion, deposits, and plugging, there are instability phenomena which can cause damage to the seating surface of a PRV and prevent it from performing properly. These are described in the following sections. Cycling, Fluttering, and Chattering The total non-recoverable pressure loss between the protected equipment and the PRV should not exceed 3% of the PRV set pressure, to prevent valve instability; with the following exceptions to the aforementioned criteria [9]: Thermal relief valves: PRVs designed solely to protect against the overpressure caused by liquid hydraulic expansion, due to ambient or process heating. They are largely oversized for the relief requirement, which could lead to cycling. Moreover, it may result in exceeding the 3% criteria. However, this would only be a concern for isolatable equipment; should it happen, the amount of trapped liquid would be limited. In that case, as the relief device opens and discharges a volume of liquid, it subsequently recloses due to loss of built-up pressure on the inlet of the valve. It would not immediately reopen because it takes some time for the pressure to build up again. Chattering is not expected for this case. Process Safety Progress (Vol.37, No.1) March 2018 37

Remotely sensed pilot operated relief valves: this arrangement for pilot operated relief valves permits the relief device to sense the pressure directly from the protected equipment. This prevents the relief device from reclosing due to high, non-recoverable pressure losses. The concern in exceeding the 3% rule is that it may result in one of the following instability phenomena which may be observed on pressure relief valves [10]. Cycling Cycling refers to low frequency opening and reclosing of a relief device, tending to occur when the relief requirement is small compared to its capacity. The pressure in the system decreases, then builds back up again periodically. This low frequency movement does not usually result in damage to the PRV; however, it does impact the ability of the valve to reseat and may lead to wear over time. Fluttering Flutter occurs while the device is open. Moving parts of the valve are rapidly reciprocating, however, the disk does not contact the seat; instead, it reciprocates around a point, creating pressure pulsations. Over time this may lead to the valve becoming stuck open. This phenomenon wears out the components of the valve. Chattering Chattering is a very high frequency and high amplitude oscillation; in the worst case, the disk may move between its two extremes of completely closed and maximum lift. The frequency of the oscillations may exceed several hundred hertz [11]. Different from the cycling, the main consequences of this event are possible loss of containment, damage to moving parts of the device, and damage to the equipment to which the valve is connected. Chattering can be very destructive to the valve seat. A recent method has been proposed in API STD 520 Part II to investigate if a relief device would chatter upon its relief [12]. Experience has shown that a relief device may start chattering when the unrecoverable pressure losses are below the 3% recommended limit; conversely, even if the losses are above 3%, the PRV may not chatter or result in failures due to relieving events. Because the relationship between inlet pressure drop and chattering is not well understood, detailed requirements for an engineering analysis are the responsibility of the user. The standard states that the user s engineering analysis may be qualitative or quantitative and shall be documented. Readers are cautioned that an engineering analysis shall not be applied if the relief device has a history of chattering. Causes of PRV Instability Several sources discuss the main causes for PRV instability and are listed below. PRV instability is a complex occurrence and often cannot be attributed to a single cause. Excessive Inlet Pressure Losses As the relief valve opens, the pressure on the inlet nozzle decreases due to the pressure losses resulting from friction in the inlet piping. If the pressure losses are significant, the inlet pressure may fall below the reseating value for the PRV, which will result in the device reclosing. As the pressure on the protected equipment builds up again, the valve will reopen. This effect may lead to chattering on the relief device [13]. Excessive Built-up Backpressure Built up backpressure, due to flow in the discharge piping of the PRV, results in a force on the valve disk, which in turn may reclose the valve. If the backpressure is excessively large, the valve will close, only to reopen again after the flow stops and the force ceases. This is also a cause for chattering on the relief device [14]. Acoustic Interaction The rapid opening of a relief valve results in an alsorapid drop on the pressure upstream of the valve disk. As a result, a pressure reduction wave travels through the upstream fluid; when it comes in contact with an upstream reservoir it reflects and travels back, as a compression wave towards the valve disk. If this wave reaches the disk before it closes, the valve may discharge in a stable manner or it may flutter. If the disk is closed, however, it may lead to a cycling or a chattering effect [15]. Retrograde Condensation If the fluid during the relief scenario is supercritical (e.g., pressure relief valves protecting high pressure system on hydrocracker units), the drop in pressure as the valve opens may lead to partial condensation of the fluid. When this condensation occurs, there will be an increased pressure drop effect due to the contraction of the fluid from supercritical to liquid [16]. Improper Valve Selection Vapor certified valves will open faster than liquid certified ones. For services with only liquid relief, a vapor certified valve would open much faster than what is required, as the pressure buildup on a liquid service is also slower, which in turn may lead to reclosing the valve right after it starts relieving [17]. Oversized Relief Valves An oversized valve is one in which the capacity greatly exceeds the relief requirement. This commonly occurs when specifying a PRV for equipment which has credible scenario(s) with large relief requirements; however, other scenarios or minor upsets may only need to relieve a fraction of that amount. Conservatism in sizing (oversizing) can lead to on off cycling [18]. Body Bowl Choking An additional cause for PRV instability is given by the Center for Chemical Process Safety (CCPS) [19]. The velocity at the outlet flange of a conventional PRV reaches sonic velocity in cases of larger PRV sizes and higher set pressures. This phenomenon is known as body bowl choking. When this occurs, the pressure in the valve body rises regardless of the back pressure at the PRV outlet. This pressure rise in the PRV body may in turn cause reduced lift and/or unstable motion of the valve. Inherently Unstable Operation In addition to the factors outlined above, the stability of the PRV is influenced by dynamic forces acting to open and close the valve, and the various factors which affect those forces. Darby et al. derived and tested a model for the opening lift dynamic response of a pressure relief valve in gas/ vapor service [20 22]. This response depends on physical characteristics of the valve and the valve flow characteristics, operating conditions, inlet line and discharge piping, and capacitance of the protected vessel. They concluded the model was capable of reasonable replication of the dynamic response of valves tested, including instabilities, and further concluded that it is difficult to generalize the influence of 38 March 2018 Published on behalf of the AIChE DOI 10.1002/prs Process Safety Progress (Vol.37, No.1)

any one parameter due to the highly nonlinear nature of the system. DETERMINING INSPECTION INTERVAL Both the National Board Inspection Code (NBIC) Part 2 and API RP 576 provide guidance on inspection and test frequencies for pressure relief valves, including manual checks, pressure tests (pop tests), and service intervals (preventive maintenance) [23,24]. Both standards state that the normal interval between shop inspection/overhaul is determined by operating experience and the environment the relief device is subjected to; therefore, it is expected that a valve with one or more of the following would require a shorter interval than a valve in clean, non-fouling or non-corrosive service: Corrosive or fouling service; Common discharge header; System critical to plant operation; Discharge particularly detrimental (fire hazard, environmental damage, toxicity); Subject to vibration; Low differential between set and operating pressures; Frequent operational upsets; or Leakage problems. Establishing shop inspection/test history for a valve is therefore vital to the process of establishing its test interval. Where several sequential tests of the as received valve reflect test results consistent with the cold differential test pressure (CDTP), and no change in service is expected for the valve, an increase in the test interval may be considered, if allowed by local regulations. On the other hand, if the tests show a history of erratic results, evidence of PRV instability, or significant deviation from CDTP, the test interval should decrease and/or the valve installation should be modified to improve performance. Note that both standards suggest inspection frequencies where test records and/or inspection histories are not available; the NBIC provides these for various equipment types, for example, annually for PRV s in steam service or five years for PRV s in propane or refrigerant service. Both standards state that if the effects of corrosion, system fluid, or service conditions are unknown (for new processes, e.g.), a relatively short inspection interval, not to exceed one year, should be established. RISK-BASED INSPECTION OF PRV S API RP 576 states, In API 510, the subsection on pressure-relieving devices establishes a maximum interval between device inspection or tests of 10 years, unless qualified by a risk-based inspection (RBI) assessment. [25]. This approach is accomplished through RBI method of utilizing Risk to manage and prioritize an inspection program based on API RP 581 [26]. The following steps are based on a recent RBI case study, in which it is assumed that all PRV s were inspected in accordance with API RP 576, and includes the assumption that all PRV s have been sized, selected and installed per API STD 520 Part II. The details of Consequence of Failure (COF) and Probability of Failure (POF) regarding PRV s will be demonstrated below. COF was analyzed by defining the types of overpressure scenarios, the discharge location of the relief valve, and if there were multiple relief valves in parallel. POF was analyzed by defining the number of overpressure scenarios, fluid service severity, relief valve type, if a rupture disk existed upstream of the relief valve, and inspection history. The resulting risk, recommended inspection interval, and next inspection date can then be determined. PRV RBI Decision-Making The following decision-making occurred in two steps: (1) Reviewing applicable sections from API RP 581 [27]; and (2) Reviewing equipment and piping applicable data to determine what items that addressed COF and POF could actually be analyzed. Risk Matrix The case study was performed using API RP 581 5x5 risk matrix [28]. Consequence of Failure (COF) Consequence is set up as A E (X-axis of the Risk Matrix), equivalent to Very Low, Low, Moderate, High, and Very High (respectively). The COF is evaluated by considering each PRV and noting what equipment (and/or piping) or pieces of equipment are protected by that particular valve. Observe the RBI analysis for the protected equipment and start with the COF for that equipment. If there is more than one piece of equipment protected by the valve, use the highest COF to be conservative. If a pump is the piece of equipment being protected then defer to the piping associated with the pump and use the COF for the piping. After determining the starting COF for each PRV, determine the types of overpressure scenarios, the discharge location of the relief valve, and if there are multiple relief valves in parallel with the valve that is being reviewed, for example. Overpressure Scenarios Identify the overpressure scenarios. Utilize API RP 581 Table 7.2 (Default Initiating Event Frequencies) and consider the overpressure scenarios that have an Event Frequency of 1 per 10 years or less, per the case study. Therefore the following are considered. The following scenarios have an Event Frequency of 1 per year. Runaway Chemical Reaction The following scenarios have an Event Frequency of 1 per 5 years. Tower Pump Around Failure or Reflux Pump Failure The following scenarios have an Event frequency of 1 per 10 years. Blocked discharge, without administrative controls in place Loss of cooling water utility Thermal/hydraulic expansion relief, without administrative controls in place Control Valve (CV) failure, initiating event is same direction as CV normal fail position (i.e., Fail safe) Liquid overfilling without administrative controls Discharge Location Adjustments can be made to the PRV consequence based on the discharge location for each PRV, For example: Atmosphere Increase the (COF level) Flare system Decrease the (COF level) Closed Process Increase the (COF level) Closed Drain (underground piping, or liquid portion of the flare system) Decrease the (COF level) Process Safety Progress (Vol.37, No.1) Published on behalf of the AIChE DOI 10.1002/prs March 2018 39

Probability of Failure (POF) Probability (Likelihood) is set up as 1 5 (Y-axis of the Risk Matrix) equating to Highly Unlikely, Unlikely, Possible, Somewhat likely, and Very Likely (respectively). All PRVs started with a likelihood category of 3 or Possible. Observe the number of overpressure scenarios, fluid service severity, relief valve type, and if a rupture disk existed upstream of the relief valve, and the inspection history. Number of Overpressure Scenarios Observe the Estimated Demand Rate (from applicable scenarios in Table 7.2 Default Initiating Event Frequencies) total number of scenarios (Total for all equipment protected). The POF should be adjusted based on the number of overpressure scenarios. Fluid Service Severity There are two different types of PRV Service Severity as described in API RP 581 [29]. One is based on Fail to Open cases and the other is based on Leak only cases. Determine the severity level for each PRV based on the descriptions in API RP 581 Categories of PRD Service Severity (Fail Open Case) Table 7.4 and (Leak Case) Table 7.11. The probability will be adjusted relative to fluid service based on the determined severity level for the fluid service. If the device protected multiple pieces of equipment, note the service for each piece of equipment and note the severity for each one. Use the worst severity to make the adjustments. Valve Type Because the Probability of Failure on Demand vs. Time in Service is based on Weibull parameters which were determined using industry failure rate data, using the valve type as a variable for probability of failure was considered unreasonable in this case study (See API RP 581 Fail to Open Table 7.5/Figure 7.2 and Leakage Table 7.12/Figure 7.3). Rupture Disk Upstream If there was a rupture disk upstream of the PRV then the probability should be slightly lowered. Historical Inspection Data Review the case study inspection data and determined which types of relief device inspections have been performed. Determine the actual inspection interval for the last two inspections by comparing the date for the last shop inspection/overhaul and the second to last shop inspection/ overhaul. If there was no second to last shop inspection/ overhaul, then the other option is to use the date three years prior to the last shop inspection/overhaul. Check if a visual On-stream inspection had been performed. Evaluate if the last shop pre-test Passed or Failed. Grade the last inspection data based on API RP 581 Table 7.7 Inspection and Testing Effectiveness. A 5 Highly Effective to D 5 Ineffective. Record the next inspection due date. Determine if the next inspection was overdue relative to the date of the current analysis. If the next inspection is overdue, then the probability of failure should be increased. Resulting Risk By now the PRV has a defined COF (shown as Consequence on API RP 581 5 x 5 Risk Matrix) A E, Very Low, Low, Moderate, High and Very High (respectively). It also has a defined POF (shown as Probability on API RP 581 5 x 5 Risk Matrix) 1 5, Highly Unlikely, Unlikely, Possible, Somewhat likely, and Very Likely (respectively). These are based on the operating company s risk-ranking acceptance criteria. With these defined Consequence and Probability Numbers and Letters, there are resulting risks of High Risk, Medium High Risk, Medium Risk and Low Risk. Note: The distribution of the number of PRV s are placed in the Risk Matrix proper designations. As a result, the summary of the consequent risk distribution shall be as follows: High Risk 5 (Total numbers of PRV s assigned in the high risk matrix section) Medium High Risk 5 (Total numbers of PRV s assigned in the medium high risk matrix section) Medium Risk 5 (Total numbers of PRV s assigned in the medium risk matrix section) Low Risk 5 (Total numbers of PRV s assigned in the low risk matrix section) Based on the resulting risk information, the next inspection intervals should be focusing on high risk PRV s while the inspection frequency regarding the low risk PRV s can be reduced or even greatly reduced compared to the usual inspection program. This results in considerable inspection and general cost reduction. Therefore, implementing RBI provides a dependable methodology of determining the best combination of inspection frequencies and inspection scopes. ROLE OF PRESSURE RELIEF ANALYSIS Pressure relief analysis (PRA) studies and periodic revalidations provide a comprehensive database of potential sources of overpressure and can be used to develop a concern list summarizing any deviations from industry and operating company standards. During a pressure relief analysis on a unit, it is possible to identify and quantify: Non-recoverable pressure losses on the inlet piping to the relief valves; Built-up backpressures on the outlet piping; Undersized overpressure scenarios; Oversized overpressure scenarios; Acoustic interaction on the piping; Improper valve selection; Improperly installed relief valves; Liquid static head on piping that could prevent relief valves from opening prior to the protected equipment exceeding its MAWP plus allowable accumulation; Obtaining all the above mentioned data, which are outputs of PRA, is beneficial to identify relief valves that could present instability (even if they never presented before) and to judge in a more assertive approach which actions can be taken to prevent instability for that devices. CONCLUSION As previously mentioned, the 10-year interval should be considered as a maximum time between inspections. A risk-based approach, as illustrated on this paper, is able to improve on the inspection management of PRVs by providing a dependable methodology of determining the best combination of inspection frequencies and inspection scopes. DISCLAIMER The information contained in this document represents the current view of the authors at the time of publication. Process safety management is complex and this document cannot embody all possible scenarios or solutions related to compliance. This document is for informational purposes 40 March 2018 Published on behalf of the AIChE DOI 10.1002/prs Process Safety Progress (Vol.37, No.1)

only. Siemens makes no warranties, express or implied, in this paper. Literature Cited 1. American Petroleum Institute, API Standard 521, Pressure-relieving and Depressuring Systems, 6th Edition, 2014 Table 1. 2. U.S. Department of Labor Occupational Safety and Health Administration, 29 CFR 1910.119 Process Safety Management of Highly Hazardous Chemicals, 1992. 3. American Petroleum Institute, API Standard 510, Pressure Vessel Inspection Code: In-Service Inspection, Rating, Repair, and Alteration, 10th Edition, 2014. 4. American Petroleum Institute, API Standard 520, Sizing, Part II-Installation, 6th Edition, 2015. 5. American Petroleum Institute, API Recommended Practice 2009. 6. National Board of Boiler and Pressure Vessel Inspectors (NBBI) NB 23-2015, National Board Inspection Code (NBIC) Part 2 Inspection, 2015 Edition. 7. American Society of Mechanical Engineers, ASME Boiler and Pressure Vessel Code, Section VIII Division 1, 2015 Edition. 8. American Society of Mechanical Engineers, ASME Boiler and Pressure Vessel Code, Section I, 2015 Edition. 9. American Petroleum Institute, API Standard 520, Sizing, Part II-Installation, 6th Edition, 2015, 7.3.4. 10. American Petroleum Institute, API Standard 520, Sizing, Part II-Installation, 6th Edition, 2015, 7.1 7.2. 11. A. Borg and S. Jakobsson, On the Stability of Pressure Relief Valves: A numerical study using CFD, Master s Thesis, Chalmers University of Technology, 2014, Available at http://publications.lib.chalmers.se/records/fulltext/ 211055/211055.pdf, Accessed 25 January 2017. 12. American Petroleum Institute, API Standard 520, Sizing, Part II-Installation, 6th Edition, 2015, 7.3.6. 13. American Petroleum Institute, API Standard 520, Sizing, Part II-Installation, 6th Edition, 2015, 7.2.2. 14. American Petroleum Institute, API Standard 520, Sizing, Part II-Installation, 6th Edition, 2015, 7.2.3. 15. American Petroleum Institute, API Standard 520, Sizing, Part II-Installation, 6th Edition, 2015, 7.2.4. 16. American Petroleum Institute, API Standard 520, Sizing, Part II-Installation, 6th Edition, 2015, 7.2.5. 17. American Petroleum Institute, API Standard 520, Sizing, Part II-Installation, 6th Edition, 2015, 7.2.6. 18. Design Institute for Emergency Relief Systems (DIERS), Emergency Relief System Design Using DIERS Technology, Wiley, New York, NY, 1992, pp. 91 93 19. Center for Chemical Process Safety (CCPS), Effect of Body Bowl Choking on Pressure Relief Valve Stability, AIChE Academy Webinar, Available at http://www.aiche.org/academy/videos/conference-presentations/effect-body-bowlchoking-on-pressure-relief-valve-stability, Accessed 25 January 2017 20. R. Darby, The dynamic response of pressure relief valves in vapor or gas service part I: Mathematical model, J Loss Prevent Process Ind 26 (2013), 1262 1268. 21. A. Aldeeb, R. Darby, and S. Arndt, The dynamic response of pressure relief valves in vapor or gas service part II: Experimental investigation, J Loss Prevent Process Ind 31 (2014), 127 132. 22. R. Darby, and A. Aldeeb, The dynamic response of pressure relief valves in vapor or gas service part III: Model validation, J Loss Prevent Process Ind 31 (2014), 133 141. 23. National Board of Boiler and Pressure Vessel Inspectors (NBBI) NB 23-2015, National Board Inspection Code (NBIC) Part 2 Inspection, 2015 Edition, 2.5.8. 24. American Petroleum Institute, API Recommended Practice 2009, 6.4.2. 25. American Petroleum Institute, API Recommended Practice 2009, 6.4.1.3. 26. American Petroleum Institute, API Recommended Practice 2008. 27. American Petroleum Institute, API Recommended Practice 2008, Part I 7. 28. American Petroleum Institute, API Recommended Practice 2008, Part I Figure 4.2. 29. American Petroleum Institute, API Recommended Practice 2008, Part I 7.6. Process Safety Progress (Vol.37, No.1) Published on behalf of the AIChE DOI 10.1002/prs March 2018 41