*The views in this paper are entirely the authors and do not necessarily reflect the views of, or conditions or events occurring

at, BP America Production Company or its affiliates.

VENDOR SUPPLIED EQUIPMENT:

ENSURING PSV DESIGN MEETS PSV SPEC

Jeffrey Heil, P.E.

Inglenook Engineering, Inc.

15306 Amesbury Lane

Sugarland, TX 77478

jeff@inglenookeng.com

832-457-1862

Brian Pack, P.E.*

BP America Production Company

501 Westlake Park Blvd

Houston, TX 77079

brian.pack@bp.com

281-366-1604

Synopsis

A review of vendor packaged well site and gathering facility gas conditioning equipment demonstrates

the need for owner/operator review or oversight of overpressure protection design.

Abstract

Gas processing facilities often include standard equipment and process units that are assembled onto one

or more skids by the vendor or packager. These systems may be sold or are often rented to operators for

use at their facilities. Much care is taken during procurement to ensure the packaged equipment meets

various operating company standards on a wide range of design details, such as, pressure and

temperature rating, metal thickness and corrosion allowances, paint color, and welding procedures;

however, experience shows that the overpressure protection system design is often overlooked or looked

at in isolation, which does not allow the packager to view process hazards outside of the equipment

being supplied. The operator is then left to retrofit appropriate relief systems on delivery, or worse,

inadequate overpressure protection systems are placed into service. The Authors’ will share their

experience in review of several common packaged, skid mounted systems and provide recommendations

for specific relief system design issues commonly found with each type of system. In closing, a work

process and generalized checklist will be recommended in order to help facilitate communication

between the operator and supplier of these systems, ensuring alignment exists between the operator and

packager, and the relief system design is consistent with industry, or operator, standards.

VENDOR SUPPLIED EQUIPMENT:

ENSURING PSV DESIGN MEETS PSV SPEC

Jeffrey Heil, P.E.: Inglenook Engineering; Sugarland, TX

Brian Pack, P.E.; BP America Production Company; Houston, TX

Introduction

Operators of oil and gas processing facilities often have a unique relationship with the equipment that

they are responsible for operating in a safe and cost effective manner. Due to limited internal resources,

limited operations or maintenance experience, and/or in an effort to minimize engineering costs and

reduce delivery time, certain common pieces of equipment found at upstream and midstream processing

facilities is rented, leased or purchased in the form of a packaged equipment skid from a third party

vendor or packager. A side effect of relying on a third party vendor is that the operator of the equipment

does not have the same level of intimacy with the equipment design as they would if the equipment were

designed for a specific facility, overseen by a dedicated design team and subject to the operator’s

internal quality assurance standards. While these issues can be addressed between the operator and

packager through supply chain agreements, often these can become complex or difficult to enforce when

large volumes of equipment are purchased or rented. As a result, procuring complex packaged

equipment, such as a multi-stage gas compressor or wellhead three phase separator, is sometimes treated

similarly to procuring a simple methanol injection pump skid. As long as the packaged equipment can

meet the desired operating conditions such as pressure and throughput, it is often accepted by the

operator and installed with few additional questions asked. Often, the smaller the operator, the more

correct this generalization becomes. In this scenario, the operator assumes that the packager knows and

designs to the operator’s and industries design practices, while the packager assumes that the operator

would have disclosed any specific requirements for the packaged skid being supplied. In many aspects

of the design these assumptions are valid, largely due to various API Design Specifications for common

types of processing equipment. Unfortunately, the relief system design for equipment contained on

packaged equipment skids often suffers from this standardized equipment approach and in many cases

may not be sufficient to prevent overpressure of the equipment or a potential loss of containment.

The amount of information available as a reference for relief system design can be overwhelming to an

engineer who does not have an established background in this niche of process engineering. Federally

adopted regulations (ASME Section VIII, Boiler and Pressure Vessel Code), industry standards (API

Standard 520 Parts 1 and 2, Sizing, Selection and Installation of Pressure Relief Devices and API

Standard 521, Pressure Relieving and Depressuring Systems) and Recognized And Generally

Acceptable Good Engineering Practices (RAGAGEP) can all help an engineer in designing an adequate

relief system for a given process. Additionally, there are literature references that outline common relief

system deficiencies at the refinery or plant level (Berwanger et al., 2000; Pack et al., 2013) and

suggested methods to establish a well thought out relief system design (Wright et al., 1997; Melhem,

2013). These references fail to address the gap that forms when the design of a relief system is left

partly to chance in the belief that, a) there is a basis of design developed by the packager the first place;

and, b) the packager employs engineers who possess the necessary relief system design experience. It

has been observed on a number of occasions for such systems that, a) the relief system design is present,

but does not address all aspects of the packaged equipment operation; or, b) more commonly, there is a

blanket installation of a pressure relief device on all similar pieces of equipment with no supporting

engineering design. The operator may be unaware of the potential problem because in their mind it is

someone else’s equipment and the owner must have an accurate relief system design basis for it, or they

bought a complete package and the relief system design basis must be correct and included in the

supporting documentation. The packager may be unaware of the potential problem because they may be

inexperienced in relief system design, were not given clear guidance on relief system design

requirements, or cannot fully predict the effects of equipment outside of the packaged skid being

provided will have on the relief system design for the particular skid.

Through the Authors’ experience in reviewing over 5,000 pressure relief systems in upstream and

midstream operations, a trend was observed where specific deviations from industry best practices

(concerns) were routinely identified in preassembled equipment skids. Specific types of preassembled

equipment skids often contained similar relief system design concerns allowing some conclusions about

their relief system designs to be drawn and recommendations to address these concerns to be made.

This paper will discuss a series of relief system design concerns that are often found in three specific

types of assembled or packaged equipment skids found at gas conditioning facilities. While many of the

concerns discussed in this paper are specific to a particular piece of packaged equipment, some are

common issues present in more than one type of equipment skid. The installation of non-API 526

pressure relief devices resulting in excessive device back pressure and assuming combustible fluids will

not result in an area pool fire are two such examples. Beginning at the wellhead, this paper first

discusses a three phase separator and inlet heater skid, often referred to as a gas production unit (GPU).

From here, a typical portable compressor skid is discussed, which may be found throughout upstream

and midstream processes depending on pressure requirements. The final type of packaged equipment

discussed is a skid mounted dehydration unit found routinely at the wellsite downstream of the three

phase separator. Following the discussion of the potential relief system design concerns with these three

types of skid mounted systems, a set of recommendations is made and a specific guideline suggested

assisting both the operator and the packager in ensuring that the relief system design meets the

appropriate relief system specifications.

Wellhead Three Phase Separator

Introduction

Production streams from typical on-shore oil and gas wells are conditioned through a three phase

separator with some form of pre and post heating ability, usually through a heated glycol bath. This

combination of equipment is often referred to as a gas production unit (GPU). The system separates the

multiphase inlet stream into individual gas, oil and produced water streams that may be further

processed or sent directly to storage, be it a tank or pipeline. Due to the common functionality and

design criteria of wellhead 3-phase separators across a production asset and the industry in general, these

systems often come in the form of a third party packaged skid unit. The packaged skid includes the

choke valve, direct or indirect heated glycol bath, separator, heater fuel gas scrubber and all associated

instrumentation.

Multi-phase flow from the wellhead (or sand separator if one is used) is preheated through the skid

mounted heater and then flows through the production choke valve, which drops the pressure from

wellhead pressure to pipeline pressure or something less than pipeline pressure if downstream

compression is required. After the choke valve, flow generally makes one or more passes through the

aforementioned heater in order to counter some of the cooling that occurred due to the pressure drop and

Joule-Thomson effects, before entering the three phase separator. Gas exits the separator where further

processing may occur, such as dehydration and/or compression and is then sent to a gathering system

pipeline. A small secondary gas stream is often taken off of the separator, sent through a final heating

pass and then depressured to the skid’s fuel gas system that fuels the heater and operates some

instrumentation. Oil and produced water exit the separator through independent level control valves.

Liquid flow is sent downstream for further processing and/or storage. Figure 1 outlines the wellhead

separation process, shows the boundaries of the packaged inlet separation skid and highlights some of

the common relief system design concerns found on this type of a skid.

Figure 1: Wellhead 3-Phase Separator Schematic

Increased Flow through Choke Valve

Wellsite separation units are designed to a maximum operating pressure and throughput capacity with a

protecting pressure relief device specified that has stamped capacity greater than that of the production

skid. Flow into the production skid is controlled by the production choke valve that has either a fixed or

adjustable choke orifice installed. The size of this orifice and upstream wellhead pressure directly

affects the amount of flow that passes through the choke valve. Increases in upstream pressure or, more

commonly, the size of the orifice will result in an increase in flow to the separator. The duration of the

increase in flow is a function of how much flow the formation is capable of producing. If the increased

capacity of the orifice is less than the formation production rate, flow may be sustained indefinitely. If

the capacity of the orifice is greater than the formation production rate, flow will become un-choked and

limited by the formation once the initial pressure difference across the valve reaches steady state. In a

fixed choke valve, the diameter may be increased due to erosion or erosion-corrosion of the fixed choke

orifice within the device over time. Erosion or erosion-corrosion is usually greatest during the initial

stages of a well’s life when production pressure is also highest, further increasing the potential for

higher than expected flow across the choke valve. The diameter of an adjustable choke valve can be

increased through the purposeful or inadvertent opening of the valve past its intended set point, or

instrumentation error if the choke valve is connected to a process control system. Increases in upstream

pressure are not typical during the life cycle of a wellhead, but are not impossible either. The

application of enhanced recovery techniques such as hydraulic fracturing or horizontal drilling can

greatly increase the production rate and operating pressure of a wellhead. The Authors’ have

encountered installations where a vertical or horizontal well was taken off line, additional horizontal

laterals drilled increasing the well’s pressure, and the same separation skid reconnected when the well

was brought online.

Whether a separation skid is installed at a wellhead operating at a higher pressure than anticipated or the

choke valve is opened beyond the current desired set point, the end result is the same: an increase in

flow going to the separator. If the separator and downstream equipment can handle this increased flow,

it is possible the design gap will go unnoticed until an overpressure scenario occurs and, because relief

devices often have a lower excess capacity margin than the equipment they protect, a problem may arise.

The most common overpressure scenario that occurs is one or more of the separator outlets getting

blocked in. Closing one or more of the separator outlet valves prior to isolating the wellhead is a leading

cause of production separator blocked outlets and has led to several scenarios resulting in a relief device

opening. If such a scenario occurs and the protecting pressure relief device does not have sufficient

capacity to handle the excess flow from the well, excess overpressure of the inlet separator may occur.

Correctly identifying all credible flow related overpressure scenarios and ensuring that the installed

pressure relief device has sufficient capacity to protect against them is an important aspect of the design

of any separation process.

Ensuring that the following flow related overpressure scenarios are accounted for in an inlet separator’s

relief system design will help to ensure that adequate overpressure protection is installed on the

separator in question. While a standard relief system design is acceptable, an evaluation to ensure that

the actual capacity the separator may be exposed to does not exceed that of the pressure relief device,

must always be made.

1. Blocked Vapor Outlet – The installed pressure relief device should be able to pass the maximum

vapor rate entering the separator skid assuming that the upstream well is operating at its shut-in

pressure and that any inlet choke valves are in their wide open position. Careful attention to erosion

or erosion-corrosion allowances in fixed choke valves is also required.

2. Blocked Oil Outlet – The installed pressure relief device should be able to pass the maximum oil

rate entering the separator skid assuming similar conditions as for the blocked vapor outlet scenario.

Careful attention should be paid to flashing potential in the oil stream as this can greatly reduce the

capacity of a pressure relief device.

3. Blocked Water Outlet – The installed pressure relief device should be able to pass the maximum oil

rate entering the separator skid assuming similar conditions as for the blocked vapor outlet scenario.

Potential for Upstream Restriction

ASME Section VIII Division 1 §UG-135(b)(1) states that “The opening through all pipe, fittings, and

non-reclosing pressure relief devices (if installed) between a pressure vessel and its pressure relief valve

shall have at least the area of the pressure relief valve inlet.” The intent of this clause is to ensure that

the piping and equipment upstream of the relief device can pass the required relief rate, reducing the

likelihood of excessive overpressure occurring upstream of the relief device connection. There are

several ways that the inlet to a pressure relief device could become restricted, reducing the ability of the

device to protect against an overpressure scenario. These include items such as the installation of

reducers, reduced port valves and valves that may fail in the partially closed position (such as butterfly

valves and gate valves orientated with the stem vertical) upstream of the relief device. Less obvious but

equally troublesome restrictions are also present such as filter elements, blockages in demisting pads and

heat exchanger tubes as discussed in the portable gas compressor section. These blockages are often the

result of wet gas, cold temperatures and inadequate insulation or heat tracing. Potential restrictions in a

relief path may be found in a variety of equipment installations beyond the Inlet Separator.

While these are all of concern, the potential for freezing of fluid in an upstream demister pad or within

the relief device are especially relevant to upstream separation operations where wet gas streams and

freezing temperatures may be present. Incidents have been observed in the past where an un-insulated

pressure relief device did not open during an overpressure scenario because the cold wet gas stream

inside of a separator had caused sufficient ice to form inside of the relief device inlet such that operation

of the device was impaired. Contributing factors to this included insufficient heating of the separator’s

contents, insufficient or no heat tracing of the relief device and no insulation to retain heat from the

process to reduce the likelihood of ice formation. If a demister pad is included in the separators design,

it can be subject to similar concerns. The small openings in the demister pad gradually build up ice due

to the wet gas stream and freezing temperatures and may eventually freeze off to a point where high

pressure fluid on the upstream side of the pad cannot flow to the protecting pressure relief device on the

downstream side of the pad.

Ensuring that restrictions in the relief path are avoided is straight forward, but requires thinking beyond

the separation skid and realizing the effects external conditions such as weather can have on the

system’s relief design. By ensuring the following actions are taken, restrictions in a relief system may

be avoided and the ability of the device to protect against an overpressure scenario may be enhanced.

1. Use full port block valves along the relief path that are locked in the open position. Butterfly valves

should be avoided and gate valves should be installed with the valve stem in the horizontal position

so that a failure of the stem will not result in the gate closing the valve.

2. If relief device freezing is possible, consider heat tracing and insulating the pressure relief device,

minimizing the potential for ice formation within the device internals.

3. If a demisting pad or other vessel internals are used, install the pressure relief device on the upstream

or inlet side of the potential blockage so that in the event a blockage does occur, the device will

relieve system pressure from the point where the pressure is being generated.

Non API-526 Relief Device

Spring loaded conventional pressure relief devices are designed to balance a number of objectives. They

must be reliable, able to pass specified quantities of fluid under a variety of conditions and cost

effective. Reliability of a relief device is ensured through the use of all mechanical components, routine

testing and inspection and by ensuring that the conditions a valve is exposed to falls within a set of

specific design limits tailored to ensure stable valve operation. Two important parameters in ensuring

valve stability (and reliability) are the inlet and outlet pressure drop that occurs when the valve is

flowing at its desired capacity. Inlet pressure drop has received some press over the past few years in

industry publications (Smith et al., 2011; Bazsó et al., 2013), through industry sponsored organizations

such as the American Petroleum Institute Sub Committee on Pressure Relieving Systems and the Design

Institute for Emergency Relieving Systems and may play less of a factor in valve stability than once

thought. Impact on stability aside, inlet pressure drop is generally more dependent on the piping leading

up to the relief device than the design of the relief device. The rationale for this is that inlet fluid

operates at close to constant density and the relief device inlet is almost always greater in cross sectional

area than the relief device orifice so choking potential is minimal. Outlet pressure drop or built up back

pressure on the other hand can be highly dependent on the relief device design, especially when vapor or

flashing liquid relief occurs, increasing the potential for choking and high back pressure within the relief

device outlet connection.

The American Petroleum Institute has attempted to help relief device users navigate the complex relief

device inlet, orifice and outlet combinations that will result in the best chances for valve stability

through the API Standard 526, Flanged Steel Pressure Relief Valves standard. Table 1 outlines some of

the valve inlet, orifice and outlet combinations that are covered by API Standard 526 and suitable for

installation on wellhead separator skids.

Table 1: Select API 526 Devices

Inlet – API Orifice - Outlet

1-D-2 1½-D-2 1½-D-3

1-E-2 1½-E-2 1½-E-3

1½-F-2 1½-F-3

1½-G-3 2-G-3

1½-H-3 2-H-3

2-J-3 3-J-4

3-K-4 3-K-6

3-L-4 4-L-6

Unfortunately, some vendors prevalent in upstream operations manufacture pressure relief valves that do

not follow API 526 design specifications. Relief valves having inlet and outlet connections of the same

diameter, or an orifice and outlet connection of the same diameter, are good indicators that a valve is a

non-API 526 relief device and more prone to valve instability due to high built-up back pressure.

Examples of such non-API 526 relief device are shown in Table 2.

Table 2: Typical non-API 526 Devices

Inlet – API Orifice - Outlet

1-D-1

1-E-1 1-E-1½

1-F-1½

1½-G-2 2-G-2

1½-H-2 2-H-2

API Standard 520 Part 1, Sizing and Selection of Pressure Relief Devices §5.3.3.1 sets a built up back

pressure limit for most conventional pressure relief device protecting against a non-fire overpressure

scenario at 10% of the device’s set point unless alternative guidance, supported by testing, from the

vendor exists. While many factors such as set pressure, fluid properties and relief device outlet piping

play into the built up backpressure for a relief device installation, anecdotal experience shows that the

end result is sometimes an installation that does not meet API Standard 520 Part 1 guidance.

Excess built up backpressure may lead to reduced valve capacity, valve instability, resulting in the rapid

cycling of the valve open and closed and, in severe instances, failure of the relief device to fully open

when required to do so. Packaged wellhead separation skids often utilize non-API 526 pressure relief

devices, especially on the separator and fuel gas scrubber that may experience excess built up back

pressure resulting in overpressure of the skid, but non-API 526 pressure relief devices may be found in a

variety of equipment installations. Avoiding a potential overpressure scenario due to valve instability is

relatively manageable: select only ASME Certified API 526 conforming pressure relief devices and

calculate the built-up outlet pressure losses for that device, ensuring that the potential for choking in the

device outlet is taken into account. The potential for choking in the relief device outlet can be checked

by calculating the pressure drop using a pipe diameter equal to that of the relief device outlet. It should

be noted that all ASME certified pressure relief devices are tested to operate properly (even non-API

526 devices), but these are often not tested with any additional pipe fittings and thus not always realistic

tests.

Portable Gas Compressor

Introduction

Many on-shore production wells, especially in the United States, operate at lower pressure and require

some form of secondary gas compression in order to meet processing and delivery requirements.

Depending on the operation, gas compression may come in the form of large 1,000+ horsepower gas

compressors installed in a centralized compression facility or small 100 horsepower compressors

installed at the wellsite. Portable gas compressors may be used to compress the gas stream off one or

more separators to pipeline pressure, to generate a high pressure gas lift stream for injection into a well

or to aid in the recovery of vapors off of a site’s low pressure storage tanks. Independent of size, the

operation of these compressors and their design is often very similar with the only difference being the

size of the skid on which they are assembled. Anecdotal experience tends to show that the smaller the

compressor skid, the more common it is in the production environment and the more prone it is to relief

system design deficiencies; therefore, these will be the focus of this paper (although parallels can be

drawn to larger compressor skids).

Gas enters the portable compressor skid through an inlet scrubber where any suspended liquids are

removed from the stream before entering the first stage of compression. Gas exits the first compression

stage and flows through a compressor motor driven air cooler to remove heat in the stream associated

with near-isentropic compression. The stream then passes through another gas scrubber prior to exiting

the compression skid if it is a single stage unit or entering the second compression stage if it is a multi-

stage unit. Two stage reciprocating gas compressors are generally more efficient and common in this

type of application. If two stages of compression are present, the gas stream enters the second stage of

compression, is cooled again and then may or may not pass through a discharge scrubber before

proceeding downstream. Portable compressors may be electrically driven, but in many upstream oil and

gas field operations are gas driven, allowing them to be almost self-sufficient. Figure 2 outlines the

portable gas compression process, shows the boundaries of a typical packaged two-stage compression

skid and highlights some of the common relief system design concerns found on this type of a skid.

One common issue identified with packaged equipment skids is the inability to predict the effects of

factors outside of the skid limits on the skid relief systems. The potential for an increase in suction

pressure during a blocked outlet is one such example of this. The potential for reverse flow from a

downstream pipeline in the event of check valve failure is another. Both of these are routinely identified

as having not been considered in the compressor‘s relief system design. Installation of the relief device

downstream of the gas cooler, which may freeze off, is another common concern and is similar to the

concern of the freezing potential of a demister pad discussed in the potential for upstream restriction

section of this paper and will not be discussed again. Secondary effects central to the skid such as an

increase in rod loading above its allowable limit may also go unaddressed in a relief system design due

to a lack of relief system design experience.

Figure 2: Portable Compressor Schematic

Secondary Effects of a Blocked Outlet

Two secondary effects of a blocked compressor outlet are going to be discussed. The first, a potential

increase in inlet pressure, is external to the compressor skid meaning it is influenced by factors beyond

the skid boundaries that were likely not addressed in the original design. The second, a potential

increase in rod loading due to an increase in the operating ratio of the compressor is integral to the

compressor design, but also goes unaddressed in many designs, especially at lower suction pressures.

The outlet of a reciprocating compressor may be blocked in by several different events. The most

common is the inadvertent closure of a downstream valve creating a block in the downstream line.

Other scenarios resulting in the same outcome include a control valve failing closed, an ice plug forming

in a downstream gas cooler or a rod failure resulting in the piston of a downstream stage failing in such a

position that flow through the compressor is blocked. Whatever the cause, the outcome will be one of

two scenarios. In the first scenario, a high pressure, temperature, rod loading or some other process

alarm recognizes conditions outside of the design envelope and shuts the compressor down before any

significant raise in pressure occurs. Portable skid mounted units generally have minimal controls such

as this and if they do, they are operated by a common process control system reducing the likelihood

that alarm “two” will trip and shutdown the compressor if alarm “one” fails to trip. Additionally, API

Standard 521 §5.10.2 does not allow the relief system designer to take credit for any favorable process

control responses that would reduce the relief requirement for a particular overpressure scenario. API

Standard 521 Annex E outlines specific integrity level requirements that must be met if instrumentation

credits are to be taken. This leads to scenario two where no positive control response is observed and

the pressure within the system begins to build until one of the mechanical limits of the system is

exceeded. A properly designed pressure relief device will protect against the latter scenario, ensuring

that the pressure within the system does not exceed the system’s maximum allowable overpressure.

One commonly overlooked aspect of relief system design is the impact on the system in question that

the upstream or downstream process may have on it. In this case, blocking the outlet of a compressor

often results in an increase in inlet or suction pressure to that same compressor. If the upstream source

of pressure supplying feed to the compressor suction is a producing well, the pressure within that well

will begin to build as soon as the outlet is blocked, up to the well’s shut-in pressure or some other

limiting pressure such as an intermediate pressure relief device’ set pressure. Increases in upstream

pressure may result in an increase in flow through the compressor and the required capacity of the relief

device in question. The increase in suction pressure reduces the required compression ratio to reach

relief conditions, increasing the volumetric efficiency and corresponding compressor capacity.

Selecting the correct process conditions and resulting required relief rate is an important aspect of

designing a pressure relief system.

The second scenario is an overlooked blocked outlet resulting from the compressor’s piston cylinder.

Often a packager will design and supply a portable compressor skid that can be used throughout a wide

operating envelope. This allows for maximum versatility in the compressor’s application, but may result

in some design aspects being overlooked. Specifying a compressor skid that has a large gap in the

normal discharge pressure and the protecting relief device set point represents one of these gaps. For

example, a compressor stage that normally compresses a 100 psia feed stream up to 400 psia has a

compression ratio of 4. If the same stage continues to compress a stream during a blocked outlet

scenario, until the relief device begins to open at 1,455 psia, the end compression ratio will be 14.5.

Compression ratios for reciprocating compressors are generally limited to a maximum of 8 per stage

(GPSA Fig 13-9) as past this point, rod loading begins to climb, increasing the likelihood of damage to

the compressor internals. A better design would be to set the protecting relief device to 600-800 psia

(pressure ratio of 6-8), allowing enough of an operating margin for proper operation under normal

conditions, but also minimizing rod loading and damage potential during a blocked outlet scenario. This

scenario was chosen for the sole reason that it represents a common installation observed throughout the

industry, especially at older fields with lower wellhead pressures.

When trying to determine the required relief rate for a blocked compressor outlet, the following thought

process should typically be followed. Many of the calculations referenced in the below process are

detailed in Chapter 13 of the Gas Producers and Suppliers Association (GPSA) Handbook.

1. Determine what the maximum expected compressor suction pressure will be for the blocked outlet

scenario in question.

2. Using the known design details for the compressor including available horsepower, fluid at suction

conditions and fluid relief conditions, determine the compressor capacity. Note that it is possible

that a compressor is horsepower limited.

3. In systems that have a large difference in normal operating pressure and relief pressure, high

compression ratios (> 8) may be present resulting in high rod loadings. This will most commonly

show up as low or negative volumetric efficiencies. When specifying a relief device’s set point, care

should be taken to ensure that high rod loading would not be required for relief to occur as this can

result in mechanical damage to the compressor and a possible loss of containment.

4. Determine what the maximum or design flowrate is from the upstream system. A compressor can

only compress the amount of gas that is fed to it and in some installations this may be less than the

compressor’s capacity.

5. The required relief rate should be equal to the lower of the compressor capacity or the design flow

rate from the upstream system at the protecting device’s relief pressure.

Reverse Flow through Recycle Line

Any time a downstream system operates at a higher pressure than an upstream system, there is a

potential for reverse flow and possible overpressure of the upstream, lower pressure system. API

Standard 521 §4.3.4 states that, a single check valve is usually insufficient to prevent overpressure from

the higher pressure system. Depending on the installation, the reverse flow event has the potential to

continue for extended durations, especially in oil and gas operations when large pipelines are involved.

The most common cause of a reverse flow overpressure scenario occurring is the failure of a check

valve between the low and high pressure systems, especially when compression is involved. Reverse

flow in portable compression skids is usually limited to the latent failure of a downstream check valve

that is not realized until a recycle or start-up valve is opened and the lower rated suction side of the

compressor is exposed to higher discharge pressure. The key aspect here is that the check valve failure

occurs latently and goes unidentified until the recycle or start-up valve is opened. The most common

time when this sequence of events occurs is during start-up or shut-down operations when the path is

open, but the compressor is not in operation.

Figure 3 outlines the reverse flow path on the system drawing for additional clarity.

Figure 3: Reverse Flow Path

Industry guidance (API Standard 521) states that if a single check valve is present on the downstream

line, the full wide open failure of that check valve should be considered. In such a scenario, the required

relief rate can be significant and is usually based on the capacity of the piping and fittings from the

downstream high pressure source and the protected lower pressure system. If multiple dissimilar check

valves are installed, the likelihood of multiple failures decreases, especially if the check valves are

inspected and maintained. This is the desired design for high pressure/low pressure interfaces like those

being discussed as the recommended required relief rates drops to the equivalent flow through an orifice

equal to 1/10th of the diameter of the largest check valve in the downstream line. Some installations may

have more than one check valve resulting in the reverse flow case becoming a lesser relief case, but

many contain only a single check valve as shown in

Figure 3 with no additional valves downstream of the compression skid before encountering larger

volumes of higher pressure fluid resulting in higher potential required relief rates

When installing a portable compressor skid, care should be given to ensure the installed pressure relief

device provides sufficient overpressure protection against any reverse flow scenarios present. The

easiest way to accomplish this is to ensure that there are at least two dissimilar check valves

immediately downstream of the compressor discharge prior to entering any larger vessels or downstream

pipelines and that an overpressure design basis accompanies the provided documentation for the

compressor. Reverse flow is especially likely when the downstream system contains a large volume of

fluid. If the downstream volume is smaller, such as a small separator vessel, a settle out calculation to

determine the maximum upstream system pressure should be completed as a scenario credibility check.

Dehydration Unit

Introduction

Gas recovered from the wellhead through the use of an inlet separator will be saturated and depending

on well conditions, may contain a significant amount of water. Due to the detrimental effects of water

on pipeline integrity, collection and transmission pipelines have strict requirements for allowable water

content. Reducing the water content of a natural gas stream then becomes an important aspect of gas

production. Newer operations are beginning to incorporate centralized gas processing (dehydration,

sweetening and compression) techniques, but in many cases dehydration of a saturated gas stream is

completed at the wellsite. In installations such as this, the volume of gas being processed is smaller;

therefore, smaller skid mounted dehydration units are often needed to meet pipeline specifications.

The wet gas stream enters the dehydration skid through an inlet particulate filter designed to protect the

dehydration column from contamination and prolong the quality of the glycol. Once filtered, the stream

enters the contactor on the bottom and rises through the column internals, contacting lean glycol flowing

from the top of the column down to the bottom. Through this exchange, glycol absorbs water from the

gas stream and dry gas exits the top of the column and the dehydration skid. In some installations, the

dry gas stream may pass through an overhead coalescer ensuring that no glycol is carried over in the gas

stream, prior to leaving the skid. Rich glycol is pumped from the bottom of the contactor to a glycol

reboiler where water is driven off of the glycol stream and vented to the atmosphere. The now lean

glycol stream passes through a filter and back to the top of the contactor where the cycle is repeated.

Figure 4 outlines the portable gas dehydration process, shows the boundaries of a typical packaged

dehydration skid and highlights some of the common relief system design concerns found on this type of

a skid.

Figure 4: Dehydration Skid Schematic

Gas Breakthrough at Spec Break

Portable dehydration skids generally contain two primary systems, the glycol or dehydration contactor

and a glycol regeneration system. The dehydration contactor will usually operate at a higher pressure

and is responsible for ensuring that the lean glycol contacts the gas stream allowing moisture in the gas

stream to be absorbed by the glycol stream, drying the gas stream. A glycol regeneration system is then

required to drive off this absorbed water vapor, usually through a combination of increased temperature

and reduced pressure. As a result of the reduced operating pressure of the regeneration system, a

specification break usually occurs at the level control valve connecting these two systems. In the event

that the level control valve fails in the open position, glycol in the contactor would drain into the

regeneration still and the higher pressure vapor within the contactor would enter the lower rated

regeneration still and surge tank, resulting in a potential overpressure scenario. Depending on the design

pressure of the intermediate exchangers, filters, and piping, the potential for overpressure may be

present upstream of the regeneration system as well.

The potential for an unidentified gas breakthrough overpressure scenario is one of the most commonly

overlooked scenarios in the relief system design of existing systems for both packaged and unpackaged

systems. A lack of experienced relief system design engineers involved in compiling packaged

equipment only increases the potential for an undersized pressure relief device due to this scenario in

packaged equipment skids. Such an oversight in relief system design is troublesome due to the high

flow rates that can often occur as a result of the scenario. When credible, gas breakthrough is typically

the design scenario for a system and ultimately determines the required relief device size. When

analyzing a system where a specification break occurs across a control point, such as the level control

valve between a contactor and regenerator, a series of steps may be taken to ensure that the potential for

gas breakthrough is taken into account.

1. Determine the maximum normal operating pressure of the upstream gas contactor. This may require

reviewing upstream systems such as a gas compressor, inlet separator or well head. In wellsite

operations, this will usually be the highest possible upstream pressure or is limited by an upstream

pressure relief device. If this maximum upstream pressure is less than the lowest MAWP of the

system in question, then overpressure due to gas breakthrough is not credible.

2. If the maximum upstream pressure exceeds the lowest MAWP of the system in question, gas

breakthrough is most likely credible. The next step should be to look at the volume of liquid present

in the upstream system and the available vapor space in the protected system. If the upstream

volume exceeds the available downstream volume then liquid relief may also be a credible

overpressure scenario and will occur before gas breakthrough does. If there is sufficient vapor space

to handle the liquid, then only vapor relief of the gas breakthrough is typically needed, but cases may

be present requiring two-phase relief consideration.

3. The required relief rate for a gas breakthrough overpressure scenario should be determined based on

the maximum upstream (gas contactor) pressure as previously discussed, the piping and fittings

along the flow path and the protected system’s (glycol heater / still) maximum allowable

overpressure. This often includes a combination of pipe, control valve and possibly orifice flow

calculations.

Combustible Liquid Pool Fire

NFPA 30, Flammable and Combustible Liquids Code §1.1.1 states that it “… shall apply to the storage,

handling, and use of flammable and combustible liquids…” NFPA 30 is one of the underpinning

guidelines, and in many states a regulation, that requires the protection of pressurized vessels against the

effects of an external or pool fire. Most of the work in industry has centered on flammable liquids

(Flash Point < 100 °F) and specifically liquids that closely resemble gasoline. As a result of this focus, a

common misconception exists that only flammable liquids may form a pool fire capable of

overpressuring a pressure vessel. As stated by the opening section of NFPA 30, combustible liquids

(Flash Point ≥ 100 °F) are also capable of fueling a pool fire and resulting in an overpressure scenario.

When reviewing systems containing or in the vicinity of combustible liquids such as lube oil, glycol,

non-aqueous amine and sulfur, the argument that pool fire is not credible as no flammable liquids are

present is routinely made. It is the hope of the Authors’ that the scope of NFPA 30 corrects this

misconception and opens the door for a discussion on how different types of liquids may impact a

systems relief system design basis.

While the system being discussed is a glycol dehydration column, the key points of this discussion are

equally applicable to other combustible liquids found in the gas processing industry such as amines, lube

oils and molten sulfur. The glycol contactor, filters, heater, surge vessel and make-up storage tanks

represent a significant quantity of glycol that may be onsite and in the immediate vicinity of a glycol

dehydration skid; therefore, the formation of a pool fire fueled by this glycol should be considered. One

important aspect that does require consideration is the heat content of glycol compared to gasoline,

which is the basis for industry’s common fire heat input calculations. API Standard 521 §5.15.2.2

provides guidance for calculating the heat input for typical hydrocarbons such as gasoline or kerosene

and are used for the majority of external fire required relief rate calculations. As these may result in

overly conservative required relief rates for fluids having lower heats of combustion such as most

glycols, more detailed calculations may be desired and are allowed by API Standard 521. One method

of easily addressing the difference in heat output between different fluids is to assign a set of derating

factors to the widely used API fire heat input equations (Hauser et al., 2001). Using the Burning Rate

Factor formula in Hauser et al., the derating factor for a typical glycol is approximately 0.5. The

derating factor is directly applied to the amount of heat predicted by the API Standard 521 fire input

equations having a direct impact (reduction) on the required relief rate for the external fire scenario in

question. The potential for an external or pool fire scenario to have been omitted for equipment

containing, or in the vicinity of, combustible fluids may be found in a variety of equipment installations

beyond the Glycol Contactor.

Ensuring that a system is adequately protected against overpressure due to vapor generation as a result

of an external or pool fire is a scenario that can be identified and quantified as such; unless the only

source of liquid in the area is not flammable or combustible, the potential for a pool fire should be

considered. Liquids not representing a potential fire source are called Class 3B liquids by NFPA and are

identified as having a flash point > 200 °F. Once the credibility of a potential external fire scenario has

been established, the required relief rate may be used using the following general guidance:

1. The liquid level used should be equal to the maximum normal liquid level in the system, including

any trays or column hold-up, up to the established maximum fire height, usually 25 feet above grade.

This is often a level dump set point or the elevation of the uppermost nozzle of a vessel if no other

limiting factor is present.

2. Wellsites and unattended facilities typically do not contain any firefighting capabilities; therefore,

credit for adequate drainage and firefighting is not usually justified.

3. When multiple vessels are protected by a common pressure relief device, the required relief rate

should be calculated for each individual vessel and then adiabatically mixed to yield the total

required relief rate for the system.

4. If the fluid is expected to have a reduced heat of combustion compared to gasoline, which glycol

does, the burning rate factor can be calculated in accordance with Hauser et al., 2001 and applied to

the calculated required relief rate.

5. Fire proof insulation as described in API Standard 521 §5.15.5 may be used to reduce the fire heat

input and thus required relief rate for protected systems.

PSV Installed Incorrectly

Incorrectly installing a pressure relief device can decrease the effectiveness of a system’s protecting

pressure relief device. With the potential for vendor specific allowances to the installation of pressure

relieving devices, this aspect of relief system design may not receive enough emphasis when it is not an

integral aspect of a project. The glycol dehydrator provides an example platform to illustrate some of

the most common installation errors observed. Installing a relief device below the liquid level of a

vessel where vapor relief is possible, installing a relief device horizontally and using undersized

common outlet lines are three issues found commonly on portable dehydration skids.

One common constraint in designing and assembling skid mounted systems is that nozzle or connection

availability may become limited, especially when trying to design a skid that may be used in a variety of

applications from low cost off-the-shelf components. Limited connection availability may result in a

pressure relief device being installed in a location or orientation on the protected system that could result

in inadequate overpressure protection or damage to the device. API Standard 520 Part 2 §9.4 states that,

“Pressure relief valves should be mounted in a vertical upright position.” Installing a pressure relief

device in the upright position ensures that all of the components within the valve remain in proper

alignment and that the valve reseats correctly, minimizing leakage. A horizontally orientated valve may

also result in improper forces on the valve spring and, in severe instances, may prevent the device from

opening properly when required to do so, leading to a potential excess overpressure scenario. Another

issue in horizontal installation arises when the device’s tail-pipe is oriented at 90 degrees (vertical) when

the connection is threaded. Cases of the resulting momentum created through the relief have

“unscrewed” the valve from the equipment it is protecting.

Relief device location plays an important role when the device is in liquid service, but vapor relief is

possible. The most common situation for this to occur is in liquid filled vessels that may be subjected to

vapor generation during an external fire scenario. Installing a pressure relief device below the liquid

level or point where vapor liquid disengagement is expected to occur may result in significant liquid

relief prior to vapor relief. If the relief device is designed for this scenario, having a liquid required

relief rate equal to the rate of volumetric displacement caused by the vaporized liquid, this would be

acceptable, but the device is rarely designed to such a scenario. As the volumetric displacement

scenario often results in a much larger relief requirement than the vapor flow rate, it is desirable to size

the relief device for the vapor relief scenario. Doing this requires that the relief device be in the vapor

space of the vessel and that sufficient vapor liquid disengagement exists to preclude two phase relief

from occurring. As long as the relieved fluid is not highly viscous or foamy, ensuring that the relief

device is installed above the vessel liquid level or at the top of the vessel if liquid full is usually

sufficient. If liquid or two-phase relief is suspected, it should be sized accordingly for these conditions

and may result in a larger relief device requirement.

The potential for a restriction in a relief device’s inlet line is discussed for the Wellhead Inlet Separator

Skid in detail. Restrictions in a relief device’s outlet may not fail ASME Section VIII code, but can

quickly result in high outlet pressure drop, valve instability and a reduction in relief device capacity.

One installation that is common with smaller relief devices and especially when they are in liquid

service is to tie multiple PSV outlet lines together to a single drain line. If the individual exit lines and

common drain line are appropriately sized for all credible overpressure scenarios this would not be a

problem, but proper sizing is not always completed. The principal drivers for inappropriate outlet line

sizes are either missed scenarios or a failure to complete outlet pressure drop calculations in the first

place. Failure to recognize that an external fire scenario may be present on a liquid glycol filter is one

commonly missed scenario. Failure to account for common mode relief scenarios is another often

overlooked situation. In this example, a pool fire around the glycol skid may result in the relief device

on both filters opening, doubling the flow through common sections of the individual system PSV exit

lines and severely reducing their capacity and ability to function properly. While quantifying the outlet

pressure drop for all credible overpressure scenarios for each in-service relief device is important, the

following steps may be taken to help minimize the likelihood of high backpressure on the installed

pressure relief devices.

1. Whenever possible, use dedicated relief device exit lines with no in-line restrictions.

2. If a common header is to be used, such as to a glycol drain, ensure that all common mode failures

such as multiple relieving devices in a single fire zone are taken into account.

Recommended Guidelines for the Operator & Packager

Because of the ubiquitous use of packaged equipment across upstream gas conditioning facilities and

onshore production wellsites, it is important that operator and packager work together to ensure relief

systems are not overlooked. While it is recognized that many packagers do not have the expertise in

design of relief systems, the operator should likely take a more active assurance role to ensure relief

systems are adequately assessed. This may require the use of internal operator expertise to provide a

relief system design to the packager. One very important message this paper seeks to send home is that

the operator and the packager cannot assume without conversation that its relief design is adequate for

the equipment. The communication lines must be open on this topic from the start of the procurement

process.

As has been demonstrated through the preceding examples, when not fully defined through clear

operator expectations and packager accepted responsibilities, the relief system design basis for packaged

equipment skids can be affected. Because of the relative simplicity of these systems versus that of grass

roots engineered equipment, a set of guidelines are here developed to ensure that the relief system

design for packaged equipment is considered. The following proposed guidelines shown in Figure 5, in

the form of a checklist, are based on principals discussed in the examples presented in this paper, but are

applicable to any systems that may be found in the gas processing industry. The user is cautioned that

these are guidelines represent minimum design components to be considered, and are not a substitute for

a thorough relief system design that should accompany all pressurized systems.

Figure 5 - Recommended Relief System Design Guidelines

Guidelines for Relief System Design of Common Skid Mounted Gas Conditioning Systems

System Specific Considerations

Multiphase Separator

Blocked vapor, oil & water outlet considered in scenario analysis.

Maximum mechanically limited (e.g. well formation or PSV set point) upstream pressure used to

determine credibility of blocked outlet.

Required relief rate for blocked outlet should be based on maximum flow at normal operating conditions.

Potential for pool fire considered recognizing supercritical conditions may exist.

Multi Stage Gas Compressor

Blocked outlet considered for compressor inlet scrubber / separator scenario analysis.

Overpressure of compressor suction due to reverse flow or compressor settle out considered in scenario

analysis.

Blocked outlet considered in scenario analysis for each compressor stage

Compression ratios during relief conditions > 8 may result in damage to compressor internals and warrant

lowering the relief device set point.

When determining the required relief rate for a blocked outlet, consider the potential for increased suction

pressure and compressor capacity.

When determining compressor capacity, credit may be taken for reduced volumetric efficiencies, driver

horsepower limitations, and limited inlet flow rates

The relief temperature during a blocked outlet should be based on isentropic compression and the

compressor’s isentropic efficiency.

Gas Contactor (e.g. glycol dehydrator or amine sweetener )

Blocked vapor and liquid outlets considered in scenario analysis.

External fire due to flammable and combustible liquids considered in scenario analysis. Credit for

reduced heat input of combustible materials may be considered.

External fire considers liquid held in trays located within the fire zone.

Gas breakthrough due to loss of upstream liquid level is considered in scenario analysis.

General Relief Device Installation Considerations

Relief device set point ≤ system limiting (lowest) MAWP.

The entire relief device inlet line is at least as big as the inlet to the relief device.

The entire relief device outlet line is at least as big as the outlet from the relief device.

The inlet and outlet pressure losses for the device are within the manufacturers recommended limits.

Relief devices not designed to API 526 warrant special attention due to the increased likelihood of high

inlet/outlet pressure losses.

Any inlet or outlet block valves are full port ball or gate valves locked in the open position.

The valve stem for block valves should be in the horizontal position

Inlet and outlet piping is free draining and contains no pockets for accumulation.

If the relief device outlet line vents to the atmosphere, it contains a drain or weep hole.

If the relief device is a balanced (bellows) type device, the body vent plug is removed.

The relief device is oriented in the vertical upright position

The relief device is installed upstream of any significant restrictions, such as a demisting pad, filter

element or gas cooler so that the system is protected in the event of a blockage.

If the relief device will be in cold and wet service, sufficient measures are taken to prevent ice and

hydrate formation within the relief system (e.g. MeOH injection or heat tracing).

System and relief device materials of construction should be checked to ensure correct pressure /

temperature ratings for their service and to ensure no material compatibility issues are present.

Relief devices discharging to the atmosphere release at a safe elevation, typically higher than any

equipment or location of personnel (6 ft above grade) within 50 ft of the discharge point.

Conclusion

In considering the necessary safeguards for any gas conditioning system one should be cognizant of the layers of protection

concept. Often the barriers forming the process safety of the system are represented in an “Onion” diagram such as that

shown in Figure 6

Figure 6 - Onion Diagram Representing Layers of Protection for a Process System

With process system at the core “peeling” away any one layer “softens” the system’s overall process

safety as core safety functions become more relied upon. For gas conditioning systems, such as sulfur

treating plants, the risk of failure of one or more of these layers increases the likelihood of failure of the

system’s process safety design. For high risk gas conditioning systems, the level of redundancy in

layers may require additional safeguards to prevent the system from ever reaching its last layer of

protection prior to loss of containment, which is often the relief valve. Because the pressure relief

device is commonly thought of as the final and (almost) impenetrable layer, relied on to prevent loss of

system integrity loss of containment, most operators maintain prescriptive specifications for how relief

or overpressure protection systems should be designed. Unfortunately, most packaged equipment

assemblers and third party owners may not have the resources or expertise to treat relief system design

to the same level of rigor. While there is certainly no ill-intent on the part of the packager in this, relief

system design not being a core part of their knowledge and expertise can result in the relief design

becoming an a “check-the-box” exercise to ensure relief protection is provided, but not necessarily

provide justification for why it’s adequate.

Where such “check-the-box” exercises have been found in packaged equipment, it may result from a

lack of communication between both the operator and the packager. The operator may have taken little

to no assurance role to provide relief devices specifications and verify their use for the skid located on

their property and operated by their employees. On the other hand, the packager also may not have

taken steps to recognize the importance of incorporating relief system design into all aspects of a skid’s

process design. Each party must recognize the importance their respective functions play in ensuring the

overall process safety of the provided packaged equipment.

The examples outlined in this paper are a small collection of situations observed by the Authors’ at a

wide variety of gas conditioning facilities throughout the United States and Canada. While the

consequences of an ineffective relief system design can be severe, correcting the design gaps that may

lead to less-than-effective relief system design can be addressed through better communication between

the operator and packager through the use of knowledgeable engineers in the relief system design

process.

Relief system design, relief device procurement and installation should be specifically addressed in

the purchasing package or rental agreement for all process equipment to be owned and/or operated

by the operator.

The operator should provide the equipment designer / assembler with copies of any pertinent relief

system design standards or specifications.

The assembler should ensure that relief system design is incorporated into all aspects of the design of

packaged equipment. Additionally, they should ensure that anyone responsible for relief system

design work has the training and experience necessary to undertake this work.

The operator should include verification of relief system design into any equipment handover,

acceptance and pre start-up safety review processes.

The guidelines provided in Figure 5 may be used as a supplement to (not a replacement for) other

relief system design standards in order to address specific issues common to the relief system design

of the gas conditioning processes discussed in this paper.

By ensuring these activities are completed for all rented, leased, pre-assembled and packaged process

systems, it is the opinion of the Authors’ that a safer process can be easily achieved. It is important to

remember that process safety design is the responsibility of everyone, not a single individual on the

team.

References

API Standard 520 Part 1, “Sizing, Selection and Installation of Pressure Relieving Devices in Refineries,

Sizing and Selection”, 8th Ed., December 2008, American Petroleum Institute.

API Standard 520 Part 2, “Sizing, Selection and Installation of Pressure Relieving Devices in Refineries,

Installation”, 5th Ed., August 2003, American Petroleum Institute.

API Standard 521, “Pressure-Relieving and Depressuring Systems”, 5th Ed., January 2007, American

Petroleum Institute.

ASME Section VIII Division 1, “Rules for the Construction of Pressure Vessels”, 2010, American

Society of Mechanical Engineers.

Berwanger et al., “Analysis Identifies Deficiencies in Existing Pressure Relief Systems”, Process Safety

Progress, Vol. 19 No. 3, Fall 2000, pg 166-172.

Pack et al., “More Than Meeting Spec: Examination of Recent Process Safety Incidents in Gas

Conditioning Systems Should be Cause for Pause”, Conference Proceedings, Laurance Reid Gas

Conditioning Conference, Norman, OK, February 2013.

Wright et al., “Efficiently Evaluate Complex Pressure Relief Systems”, Chemical Engineering Progress,

January 1997, pg 102-105.

Melhem, “A Systematic Approach to Relief and Flare Systems Evaluation”, Conference Proceedings,

AIChE Global Congress on Process Safety, San Antonio, TX, 2013.

Hauser et al., “Vent Sizing for Fire Considerations: External Fire Duration, Jacketed Vessels and Heat

Flux Variations Owing to Fuel Composition”, Journal of Loss Prevention in the Process Industries, 2001

Vol. 14 pg 403-412.

Smith et al., “Relief Device Inlet Piping: Beyond the 3% Rule”, Hydrocarbon Processing, November,

2011 pg. 59-66.

Bazsó et al., “An Experimental Study on the Stability of a Direct Spring Loaded Poppet Relief Valve”,

Journal of Fluids and Structures, 2013 Vol. 42 pg 456-465.