Pressure Relief System Design Pit-falls

In this tip of the month, we will discuss how miscalculations and incorrect analysis of potential process upsets can affect process safety.  There are many aspects in facility design engineering and process safety engineering that should be considered when designing a new facility or debottlenecking an existing one.  During these times of compressed schedules and budgets, it can become difficult to ensure all project deliverables receive the proper amount of checking and documentation.  Mistakes in engineering design and operations of the following systems can result in serious safety incidents which must be avoided.  Quality control, technical training, calculation checking and method verifications can aid in minimizing safety risks in these systems. This months’ tip will focus on Pressure Relief Systems.

Pressure Relief System Design Pit-falls from John M. Campbell & Co. on Vimeo.

Pressure Relief Systems:

A primary process system in oil and gas facilities requiring careful attention is the Pressure Relief System. The most common components in upstream pressure relief systems are:

• Protected Equipment
• Emergency Shut Down Valves
• Depressurization Valves
• Pressure Safety Valves (PSV)
• Pressure Safety Valves Inlet and Discharge Piping
• Flare Header
• Flare Knock Out Drum
• Flare Stack / Tip

The primary purpose of the pressure relief system is to ensure that the operation’s personnel and equipment are protected from overpressure conditions that happen during process upsets, power failures, and from external fires.  In some locations and facilities, it is accepted practice to vent the pressure safety valves directly to atmosphere provided the process fluid is discharged at sufficient velocity to ensure good dispersion and that the fluids molecular weight is lighter than air.  In this TOTM we will be discussing components in the pressure relief system in which detailed engineering calculations must be completed to select and install properly.

Pressure Safety Valves:

The purpose of a pressure safety valve is to protect equipment and / or piping from any possible overpressure scenario.  There are multiple industry recommended practices and standards that govern the sizing, selection and installation of pressure safety valves. Many of these are referenced in this TOTM. A study that was conducted by Berwanger, et al. [1] determined that only 65% of upstream processing facility pressure safety valves meet the existing standards.  Accurate pressure safety valve relieving requirements, scenario analysis and installation design is critical to ensure safety of the equipment and the operations staff during an upset condition. The American Institute of Chemical Engineering found that roughly 30% of process industry losses have been found to be partially attributed to deficient pressure relief systems [2].  If an upset process condition occurs with a system that has a pressure safety valve that is missing, undersized, or not properly installed, there is a potential that the equipment will not be protected and will mechanically fail.  This could result in a significant loss of fluid containment and potential fatalities depending upon the fluids contained within the process.

On March 4, 1998, there was a major vessel failure at a Sonat Exploration facility in Pitkin Louisiana.  The vessel failure and subsequent fire resulted in four deaths.  A cause of the incident was failure of a low pressure vessel open to a high pressure gas source that was not provided with any pressure relief devices [3].

In determining the relevant relieving scenarios for a pressure relief valve, it is essential that the engineer doing the evaluation has a solid understanding of the process and the process control design within the facility.  If the lead engineer is conducting an existing plant review or working on the design of a new facility, it is critical that they evaluate all potential relieving scenarios that may be required.  If a scenario is missed, then there is a possibility that the system will not be protected if that missed scenario was the limiting case.  ANSI / API Standard 521 ISO 23251, 5th Edition [5] specifies requirements and provides guidelines for examining the principal causes of overpressure; determining individual relieving rates; and selecting and designing disposal systems, including the details on specific components of the disposal system. Only with experience and training do engineers develop the competency level to complete these evaluations effectively.  Participation in Process Safety Hazards Reviews and Analyses promote the development of an engineer’s skills in identifying and resolving potential process hazards, and can help develop a junior engineer’s skills and understanding of the evaluation of these systems.

API Recommended Practice 520, 7th Edition, Part 1 [4], and the International Organization for Standardization (ISO) Standards in the 4126 series (will not all be referenced here, and it should be noted that these only apply to systems designed and installed in the European Union Member States), addresses the methods to determine the pressure safety valve sizing requirements for the different relieving scenarios and provides guidance on how to select the proper relief valve type.  Both over-sizing and under-sizing a relief valve can result in mechanical failures, thus it is critical that the valve sizing and selection are correct.

If a facility is being debottlenecked and modified all pressure safety valves that will be affected by the modification must be checked for adequate capacity.  Many facilities are not applicable to the U.S. Occupational Safety and Health Administration (OSHA) Process Safety Management (PSM)   Standard 29 CFR 1910.119 [6].It is strongly recommended that a Management of Change (MOC) procedure be used to ensure that no facility modification will pose a safety risk or undermine the existing safety equipment provided within the facility. Pressure safety valves for all modified systems must be verified to safely handle the new required rates and compositions that result from debottlenecking the facility.

In addition, it is essential that operation’s personnel are trained in the proper handling and testing of relief valves.  There have been cases when operations and maintenance personnel have increased the set pressure on a pressure relief valve that was frequently relieving.  The increase in set pressure results in the vessel operating above the stamped maximum allowable working pressure and may result in mechanical failure.  Trained staff will understand that the solution to the problem is to correct the process condition that is resulting in the high pressure, not increase the set point on the pressure safety valve.

PSV Inlet and Discharge Piping

Another area that requires close attention is the proper design of the inlet and discharge piping of the pressure safety valves.  API Recommended Practice 520, 5th Edition, Part 2 [7], and ANSI /  API Standard 521 [5] provide guidance on the installation and design of the inlet and discharge piping for pressure safety valves.

For inlet piping to pressure safety valves, the recommended practice is to maintain the inlet hydraulic losses at no more than 3% of the set pressure of the pressure safety valve.  This is because the relief valve is designed to normally close at 97% of the set pressure.  A PSV with no inlet flow will sense the same pressure as exists in the protected equipment.  Once open however, the pressure at the inlet to the relief will be the pressure at the protected equipment minus the friction loss in the inlet line.  If this friction loss exceeds 3%, the valve will close and then reopen once the flow stops. This chattering can destroy the valve.  Over sizing of a pressure safety valve can also result in “chatter” from essentially the same phenomenon. There is a potential for pressure relief valve or piping failure from prolonged “chattering” due to mechanical fatigue and potentially thermal fatigue.

If the inlet piping design cannot be configured to meet this requirement, then the use of a remote sensing pilot pressure safety valve can be used. This is not preferred due to the potential for the sensing line to plug or freeze.

Typically, relief valves are mounted almost directly on the equipment they protect.  You will often find, however, that in existing plants this is not always the case.  Some pressure safety valves may be located remotely with long inlet lines and the 3% criteria must be carefully checked.  Even with new plant designs, there are times when the piping designer must locate the pressure safety valve remotely.  It is important to always check the inlet line losses by utilizing the piping isometric drawings.

A study conducted by Berwanger, et al [1], found that 16% of all pressure safety valve installations reviewed were out of compliance with accepted engineering practices and standards as a result of improper installations.  35.5 % of these valves were out of compliance due to excessive inlet pressure drop. Experience indicates that in many older plants, the pressure safety valve inlet and discharge piping is set at the inlet size and outlet size of the pressure safety valve and the pressure drop calculations were not performed – or were performed on incorrect assumptions for inlet pipe routing. A crude oil fire occurred in a Shell facility as a result of improper inlet piping design.  This caused severe vibration and caused a 6” flange to fail, losing containment of the process stream [8].

For systems with 600# ratings and above, the valve manufacturer may supply a relief valve with an inlet flange rating of 600# and an outlet flange rating of 300#.  Be aware that a “typical” 150# flange rating on the PSV discharge piping is not always acceptable for the higher pressure systems.  The velocity at the outlet of the pressure safety valve can not exceed sonic.  Thus, for high pressure systems the flow through the relief valve may require a pressure greater than the max pressure rating of a 150# system to maintain sonic flow.  It is important to check the pressure required to maintain sonic based on the size of the pressure safety valve outlet.  If a 300# flange is required then a 300# pipe fitting is installed to expand the pipe to a diameter where the pressure corresponding to a 150# system is not exceeded.  For large systems, it is recommended to use a flare network software program to predict the backpressure at the outlet of each pressure safety valve for various relief scenarios.  During a fire, several reliefs may open simultaneously and the backpressure must be known at the outlet of each relieving pressure safety valve under these circumstances.

The piping design for the inlet and discharge of pressure safety valves should be reviewed to determine that the piping can meet the mechanical and thermal stresses that will develop when the pressure safety valves relieve.  Threaded connections for high set pressure safety valves or on pressure safety valves that are installed near vibrating equipment are not recommended.  The threaded connections have a tendency to fail or become “unscrewed” from the vibrations, and / or forces during relieving

Proper valve and discharge piping support design is essential.  Piping and valve support becomes more critical on larger pressure safety valves and pressure safety valves that have high set pressures discharging to atmosphere.  The reaction forces that can develop from the valves relieving to atmosphere can be significant.  Even though the outlet piping may not be excessively long, the internal thrust created at the 90 degree elbow as the discharge piping turns up can be excessive.  The flow will most likely be sonic velocity at the elbow and the discharge vent must be adequately supported to prevent failure. One incident occurred when the inlet piping on a 4X6 pressure safety valve set at 1350 psig failed.  The valve became a projectile as a result.  Fortunately, no one was hurt by flying debris and the gas line was isolated before the vapor cloud was ignited. This “near miss” was likely the direct result of poor welding and poor support on the valve installation.

The reaction forces in closed systems tend to be less, but in some cases the reaction forces in a closed system can become significant if there are sudden large pipe expansions or during unsteady flow conditions within the piping. Inadequate design and supports for pressure safety valves and the associated piping can result in mechanical failure during a relieving event.

Flare Header Design

If the pressure safety valve discharges into a flare header the superimposed and built up back pressure is critical and can impact the valves relieving capacity if the actual back pressure is higher than the originally calculated or assumed back pressure. The maximum allowable back pressure at which a pressure safety valve can function properly depends upon the type of the pressure safety valve. A study conducted by Berwanger, et al [1], found that almost 24% of all PSV installations reviewed were out of compliance with accepted engineering practices and standards because of improper installations.  12 % of these valves were out of compliance due to the outlet pressure drop being too high.  If the built up back pressure is greater than the maximum value the valve can function with, then the upstream pressure of the valve will increase above the set pressure of the valve as a result.  This condition increases the likelihood of a failure.

A flare network software program should be used to calculate backpressure in large relief systems.  For most pressure safety valves the maximum flow that can pass through the orifice size is larger than the required relieving flow.  The maximum flow must be used to calculate the inlet line loss and the resulting backpressure.  Modulating pilot valves can be used, if required, to control the maximum flow that is required to be relieved.  In the design of the flare system, several types of valves are available, as explained in API 520 Part 1 [4].  Conventional, bellows, and pilot valves are typically used.  The valve manufacturer must be consulted to define the maximum flow and backpressure requirements for each type of valve.  The final flare design can not be completed until the actual pressure safety valves have been selected.

Depending upon the fluids which are being relieved and the pressures involved, it is possible to have relieving events that require stainless steel discharge piping, Flare Header, Flare KO Drum and Flare Stack because of cryogenic relieving temperatures from the Joule-Thompson Effect through the pressure safety valve. There have been multiple cases where carbon steel flare headers have failed due to the cryogenic relieving temperatures that developed during relieving events.  The failure of a flare header completely undermines the purpose of the Pressure Relief System, and can result in a catastrophic event.

In today’s’ market, the recovery of NGL’s from natural gas is quite common.  Particular attention is required in designing the relief systems for the cryogenic vessels.  The pressure safety valves most likely will be relieving cold (at -20 F or below) two phase fluids.  The pressure safety valve downstream piping will be exposed to very cold temperatures when the valves relieve.  The recommended method for sizing two phase flow valves is by utilizing the DIERS equations.  API 520 Part 1, Appendix D [4] summarizes these equations and provides an example calculation.  The calculation procedure is long and tedious but it is recommended to perform a hand calculation before utilizing in house spreadsheets.  The couple of hours spent performing the calculation will provide valuable insight to the key parameters used in the equations and will serve as a verification check of a spreadsheet.

There should be no dead legs in any piping from the discharge of the relief valve to the Flare KO Drum.  Any pockets or dead legs can fill with liquids which may result in excess back pressure during relieving events There may also be large reaction forces in the flare header as a result of the slug of liquids forced down the header.  In 1999, the flare header of a Tosco refinery in California was overpressured due liquid accumulation at a low point in the flare header.  This resulted in a facility shutdown.There were no injuries reported [9].

Flare KO Drum and Flare Stack / Tip

Flare KO Drum and Flare Stack sizing is also critical to the safety of the plant.  Oil and Gas Industry Flares are designed to destroy vapor streams only and require an adequately sized Flare KO Drum to prevent flammable liquids from raining out of the flare tip.  In determining the sizing, it is important that a Flare Study be conducted to determine the worst case scenario for Flare KO Drum and Stack capacity and to select the proper droplet size separation criteria that the selected flare tip can adequately destroy.  ANSI / API Standard 521[5] provides guidance on sizing, design and selection of this equipment.

A good example of the consequences of liquids flowing out of a Vent Stack was the Texas City Refinery explosion of 2005.  This catastrophic incident resulted in a process upset where the amount of liquids that flowed to the KO Drum overwhelmed the drum size, and flowed up the vent stack and to the surrounding atmosphere which resulted in the tragic explosion [10].  If a Flare would have been installed in the Texas City Refinery rather than a Vent Stack, the consequences of the event would have been reduced.  The vapor phase hydrocarbons that were originally flowing to the vent stack would have been destroyed in the Flare Tip, and the vapor cloud that exploded would have been prevented.  Flowing liquid hydrocarbons to a Flare Tip is still a dangerous situation.  If a Flare KO Drum were overwhelmed with hydrocarbon liquids the Flare Stack would likely be raining fire, and not liquid hydrocarbons.

Based on the stack sizing, ANSI / API Standard 521 [5] outlines procedures to estimate the radiation effect from the flare.  With today’s’ specialized design of flare stacks, consultation with the flare manufacturer is recommended for the radiation confirmation.

Depressurization Valves

In the gas processing industry, it has become a standard practice to block in the treating facility with Emergency Shut Down (ESD) Valves rather than depressure the entire facility to the flare.  One primary reason for this philosophy is that natural gas fires are not equivalent to liquid hydrocarbon pool fires. Natural gas fire protection and mitigation requires different protection methods than for those used for fighting liquid hydrocarbon pool fires, which can be extinguished using a fire water system or a foam system.  . It is standard natural gas industry practice to isolate the hydrocarbon gas sources to the facility and evacuate all personnel from the facility. Once the source of the gas is isolated, the feed to the fire is terminated and the fire is quickly extinguished from lack of fuel.

In the case where a facility must be depressurized in an upset condition, careful attention must be given to the design of the depressurization valves, their timing and flare capacity.  There exists the potential to overwhelm the Flare Tip if the Tip was not designed for the high depressurization rates.  In addition, consideration for required depressurization time, resulting Flare Header temperatures, and depressurization control schemes must be given close attention.  These systems can be highly complex due to the transient nature of the process and require careful design procedures to ensure a safe Depressurization System.

To learn more about PSV Sizing, inlet and discharge PSV piping design, enroll in our Piping Systems – Mechanical Design and Specification – ME-41, Oil Production & Processing Facilities – PF-4, and Gas Conditioning and Processing – G-4.

By: Kindra Snow-McGregor
Senior Process Consultant and Instructor

References:

1. Non-Conformance of Existing Pressure Relief Systems with Recommended Practices, A Statistical Analysis, Patrick C. Berwanger, PE, Robert A Kreder, and Wai-Shan Lee. Berwanger, Inc., 2002.
2. AIChE. Emergency Relief System (ERS) Design Using DIERS Technology. American Institute of Chemical Engineers, New York, NY, 1995.
3. U.S. Chemical Safety and Hazard Investigation Board, Investigation Report, Catastrophic Vessel Overpressurization, Report No. 1998-002-I-LA.
4. Sizing, Selection, and Installation of Pressure-Relief Devices in Refineries, Part 1 – Sizing and Selection, API Recommended Practice 520, 7th Edition, January 2000.
5. ANSI / API Standard 521, / ISO 23251, Pressure Relieving and Depressuring Systems, 5th Edition, January 2007.
6. Occupational Safety and Health Standards, Process Safety Management of Highly Hazardous Chemicals, 29-CFR-OSHA-1910.119, 57 FR 23060, June 1, 1992; 61 FR 9227, March 7, 1996.
7. Sizing, Selection, and Installation of Pressure-Relief Devices in Refineries, Part 2 – Installation, API Recommended Practice 520, 5th Edition, August 2003.
8. Poor Relief Valve Piping Design Results in Crude Unit Fire, Politz, FC., API Mid-year Refining Meeting, 14 May 1985, Vol / Issue 64.
9. Contra Costa County, California, USA Contra Costa Health Services, Major Accidents at Chemical / Refinery Plants, Copyright © 2000–2009.
10. U.S. Chemical Safety and Hazard Investigation Board, Investigation Report, Refinery Explosion and Fire, REPORT NO. 2005-04-I-TX, March 2007.