Even seasoned engineers can fall into the trap of trusting valve datasheets too much. In real chemical‑processing environments, “on paper” performance can fall short — especially when factors like backpressure, fluid phase, fire exposure, or piping layout are misunderstood. This article outlines the most frequent mistakes engineers make when specifying pressure relief valves (PRVs) — from misapplying catalog flowrates to overlooking thermal expansion risks in liquid‑filled lines — and offers practical guidance for ensuring that safety valves perform as intended during real‑world plant conditions.
The problem with “on paper”
“But it matched the spec sheet” . . .
You know the drill: the specifications were checked, the datasheet was followed and everything looked good on paper. And yet, during commissioning — or worse, during an upset — some component doesn’t perform quite as expected.
PRVs are essential safety components, but their effectiveness hinges on context. Backpressure, fluid phase, fire cases and piping layout can all influence how a valve behaves in practice. The catch? Many of these factors are not easy to discern in vendor datasheets.
This article highlights the most common traps engineers encounter when specifying PRVs — not out of negligence, but because the real-world variables are easy to underestimate. Whether you’re designing for a single vessel or a large liquefied petroleum gas (LPG) installation, it pays to look beyond the datasheet.
Sizing to the nameplate, instead of the system
One common misstep in specification of PRVs occurs when engineers assume the flow capacity stated on a valve’s nameplate directly applies to their sizing calculations. But those values are based on standardized test conditions — typically 10% overpressure, atmospheric discharge and no built-up backpressure.
Reality, of course, is messier. To translate catalog capacity to real-world performance, engineers need to apply correction factors for things like the following:
- Backpressure effects (Kb)
- Gas compressibility or fluid viscosity (Kv)
- Permissible overpressure margins (% OP)
Skip these corrections, and you risk selecting a valve that simply can’t relieve pressure fast enough during an upset. Worse, the valve might remain closed or behave erratically under system conditions that deviate from test assumptions.
A sound starting point is to run the API 520 (American Petroleum Institute PRV sizing standard; www.api.org/pubs) sizing yourself using standard discharge coefficients — typically 0.975 for gas and 0.65 for liquid. That calculation gives you the minimum required API orifice size and a preliminary required capacity.
From there, share your process data and that standard orifice size with the valve vendor. They will confirm the final rated capacity, taking into account the actual coefficient of discharge for their specific valve model. And here’s the key point: if their coefficient is too low to meet your required capacity without upsizing the orifice — walk away. Sizing a valve with an unnecessarily larger orifice to compensate introduces a host of new problems, including premature lifting, stability issues and unnecessary cost.
Likewise, if you’re reviewing existing pressure-safety valve installations after a process change, re-do the API sizing and compare the required orifice size to what is installed already. Adjust for coefficient differences if needed — but don’t assume the nameplate tells the whole story.
The takeaway message is the following: Treat the nameplate as a reference point, not a guarantee. Get your numbers right first — then ask the vendor to meet you there.
Fire sizing: not just a bigger valve
There’s a common assumption that sizing for fire exposure simply means choosing a larger valve. But fire relief is a different beast entirely — it’s driven by thermal input, not process flow.
According to API 521 (Pressure relieving and depressuring systems standard), the required heat input is calculated using Equation (1).
Q = F × A × C₁ (1)
where F is the environmental factor, A is the wetted surface area, and C₁ is a heat flux constant.
From there, that heat input is translated into a mass flowrate the relief system must handle. And here are three areas where things can go sideways:
- Overlooking the F factor, which changes dramatically between an insulated vessel and an unshaded, sun-exposed tank
- Mistakenly using liquid relief equations — when fire scenarios involve vapor relief from boiling
- Neglecting blocked outlet scenarios, where flow resistance may change dramatically
Get the fire sizing wrong, and consequences range from catastrophic underprotection to nuisance valve lift that undermines reliability. The goal isn’t to oversize “just to be safe” — the goal is to size the valve specifically for the fire scenario that is actually being mitigated.
Backpressure: the silent capacity killer
Backpressure doesn’t always get the attention it deserves — but it can quietly undermines your pressure-relief system’s performance.
Any relief scenario — both superimposed (existing system pressure) and built-up (resistance from the discharge piping) — must account for backpressure. Things like long outlet runs, elevation changes, flare header congestion, or even shared discharge lines can all add up. And for conventional PRVs, even modest backpressure can reduce flow capacity, cause instability or delay valve lift altogether.
That’s why balanced-bellows or pilot-operated valves are often recommended when backpressure is significant or variable. They’re not one-size-fits-all — they come with their own design and maintenance considerations — but they’re worth evaluating early in the selection process.
So what is the bottom line? Backpressure is not just a fine-tuning detail. It’s a fundamental part of sizing. Whether you’re using vendor software or doing a manual check, it’s worth modeling up front — not discovering during commissioning.
Fluid phase confusion
Gas or liquid? It’s not always as straightforward as it seems. Depending on the relief scenario, what exits the valve can vary significantly — and so should your sizing approach. For example:
- Thermal expansion in a blocked liquid line results in liquid discharge
- System overpressure typically leads to vapor flow
- LPG or ammonia storage might produce flashing two-phase flow as pressure drops
Each case requires a different sizing equation. API and ISO (International Organization for Standardization; www.iso.org) standards distinguish them clearly, as follows:
- Gas: Use isentropic compressible flow equations that capture the behavior of expanding gases. These account for factors like the discharge coefficient (Cd), molecular weight, temperature, and gas compressibility (Z), ensuring accurate sizing under choked flow conditions.
- Liquid: Use flow equations derived from Bernoulli’s principle, which link pressure drop, fluid density and discharge coefficient to calculate the required orifice area for incompressible flow.
- Two-phase: homogeneous or non-homogeneous models
Misjudging the phase — for example, assuming vapor flow when flashing liquid dominates — can lead to major sizing errors. The result might be an undersized valve that can’t relieve pressure fast enough, or an oversized one that lifts prematurely and creates instability.
When in doubt, take a closer look at how the fluid behaves at the moment of relief, rather than just under normal conditions. It’s that phase — not the storage state — that your valve must handle.
Trapped liquid? tiny volume, big risk
Trapped liquid in an isolated line can cause sky-high pressure from even mild temperature increases. This is where Thermal Safety Valves (TSVs) come in. TSVs are small, often-forgotten, relief devices sized for thermal expansion only.
Yet many installations skip them or place them incorrectly. A few milliliters of LPG can generate hundreds of bars of pressure, if trapped. Proper TSV placement (usually at low points or between block valves) is essential.
Regulatory and inspection blind spots
Relief valve sizing isn’t just about flow equations — it’s also about knowing which rules apply. And those rules vary more than you might expect.
Standards like API 520, ASME VIII, PED, and ICPE don’t always align with each other. Each sets its own limits on things like:
- Maximum allowable overpressure
- Testing and inspection intervals
- Whether you can take credit for mitigation measures like insulation or drainage
The takeaway message is this: Stay fluent in the codes that govern your installation — and design not just for sizing, but for inspection, testing and long-term maintainability.
Maintenance: the forgotten specification
Specify it. Install it. Then forget it — until testing day. Too many PRVs are tucked behind tanks, welded into dead-legs, or installed without isolation valves — preventing routine inspection without costly shutdowns. Consider designs that include diverter valves, accessible headers, or dual-PRV setups, allowing safe isolation, testing and replacement. This foresight is not luxury — it’s risk management.
Design for reality. Use diverter valves, accessible headers, or dual-PRV setups that allow safe isolation and swap-out. This is not overdesigning — it should be considered planning for the life of the plant.
Final thoughts: question the assumptions
Pressure relief should not be thought of as just a box to check. It’s the last line of defense when everything else fails. And that means going beyond catalog values, beyond rules of thumb, and beyond blind trust.
Ask the difficult questions, such as those listed here:
- Am I sure of the relief scenario?
- Have I modeled piping losses?
- Does the valve type match the fluid state?
- Can the system handle maintenance without downtime?
If the answer to any of these is “No,” revisit the specification. Your clients, your plant, your team and your process will thank you later.
Edited by Scott Jenkins
References
- Abauzit, S., Dimensionnement des soupapes de sûreté – Sites de gaz de pétrole liquéfiés (Réf. SE5074 V1), Techniques de l’Ingénieur, 2019.
- Emerson Process Management, Pressure Relief Valve Engineering Handbook, Technical Publication No. TP‑V300, Anderson Greenwood, Crosby and Varec Products, 2012.
Author
Patrick Samuel is a French chemical engineer specializing in process design and EPC projects with a focus on clean manufacturing and industrial innovation. He has extensive expertise in plant design, process simulation, distillation, solvent recovery, thermal optimization, and operational efficiency, and is a certified Lean Six Sigma Black Belt. Patrick has delivered major industrial projects for global companies, improving both environmental compliance and production performance. He holds a Master of Engineering in Chemical Engineering from the École Nationale Supérieure des Industries Chimiques and is a recipient of the Norbert Ségard Young Hope Innovation Prize. Connect with him on LinkedIn: linkedin.com/in/samuelpatrick