Process Safety eHANDBOOK

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TABLE OF CONTENTS

Effectively Manage Large-Scale Process Hazard Assessments 7Success depends upon properly addressing a number of issues

Use Dynamic Simulation To Improve Process Safety 13A digital twin can help spot and combat risks during design and operation

Prevent The Illusion Of Protection 21Address management system failings that undermine process safety

Rethink Your Refuge 28A zero-vulnerability safe haven helps protect personnel and speed emergency response

Ensure Reliable Fire Protection in Natural Gas Plants 39Combustible and toxic gas detectors as well as flame detectors can help reduce incidents

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No official or regulatory definition

exists for large-, medium- or small-

scale process hazard assessments

(PHA). You can use a variety of factors such

as the number of nodes, their complex-

ity, the amount of people involved, or the

length of time required for a PHA to char-

acterize its size. Larger projects invariably

lead to larger PHAs. After all, such projects

typically entail considerably higher levels of

risk than their smaller counterparts.

As the size of a PHA increases, the chances

for confusion, delay or omission of critical

safety tasks grow exponentially. Inadver-

tently omitting crucial tasks leaves the

project vulnerable to safety mishaps, liabil-

ity and potential business losses. Although

techniques for conducting PHAs are essen-

tially the same for any size effort, managing

PHAs for large projects requires emphasis

on numerous issues that may not exist or be

trivial for small projects. This article looks at

strategic considerations in managing large-

scale PHAs.

THE BIG PICTUREFor any PHA, irrespective of size, key con-

siderations include:

• identifying as many process hazards as

possible in a reasonable time;

• promptly putting systems in place to

address findings from the PHA;

• reducing risk to an acceptable level and

maintaining that reduction for the lifetime

of the project (i.e., the safety lifecycle);

• effectively transmitting vital safety infor-

mation to the project sponsors;

• properly allocating the budget and

achieving cost-effectiveness; and

Effectively Manage Large-Scale Process Hazard AssessmentsSuccess depends upon properly addressing a number of issues

By GC Shah, Wood



• maintaining confidentiality and security of

data and documents.

The following strategic issues also

merit consideration:

• project sponsors and their safety practices;

• PHA infrastructure;

• PHA software;

• document management; and

• safety lifecycle management.

PROJECT SPONSORSVery frequently, large projects involve multi-

ple sponsors — with these organizations often

based in different geographic regions. Each

sponsor invariably has its own unique safety

philosophies, safety assessment procedures

and risk tolerance criteria. Unsurprisingly, their

definition of risks could differ substantially.

The lack of a common understanding of proj-

ect scope and PHA expectations increases the

chance of dissatisfied or even irate sponsors

— and may render the PHA useless. It’s not

always easy to get sponsors to agree. Diplo-

macy is a valuable trait for a PHA manager.

Here are some crucial points to keep in mind:

• Focus on getting a general agreement on

the PHA’s scope.

• Develop consensus on safety philosophy

as well as a common safety philosophy

and PHA assessment procedures for the

project. This often is covered in a strategy

document called PHA Terms of Reference.

• Establish common risk assessment criteria

and risk tolerance definitions.

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• Discuss PHA schedules, web access by

remote participants, and the number of

participants from specific sponsors. If the

sponsors are in different regions, work out

a PHA meeting schedule that maximizes

participation.

• Agree upon PHA methodology and soft-

ware (e.g., hazard and operability studies

(HAZOPs), layers of protection analyses

(LOPAs), safety integrity level (SIL) assess-

ments, or other equivalent techniques).

• Maintain confidentiality of spon-

sors’ documents.

The above list isn’t exhaustive; others points

also may be crucial and demand attention.

Early stages of PHAs involve intense and

extended discussions. Some sponsors may

feel passionately about their safety systems

and PHA methodologies. For a PHA man-

ager, this is an opportune time to establish

effective working relationships among spon-

sors. The aim is to enable the diverse group

of sponsors to work cohesively.

PHA INFRASTRUCTUREThis includes documents and data relevant

to a PHA as well as video conferencing

systems. Obviously, key documents such

as process and instrumentation drawings

(P&IDs), process flow diagrams, heat and

material balances, cause and effect dia-

grams, equipment data sheets, drawings,

and applicable regional regulations are

vital; they should be instantly available for

the PHA. In addition, consider the follow-

ing issues:

• When a PHA occurs during an ongoing

project, keeping track of documents can

be difficult. Isolate and “freeze” all relevant

P&IDs. As the project progresses, record

appropriate notes as a part of the docu-

ment management task.

• Ensure the video conferencing system is

compatible with the information technology

(IT) systems of all sponsors. (This point may

seem obvious but it’s easy to miss.)

• Include different units of measurement in

documents when this would help sponsors.

For example, report flow rates in gal/min

and m3/hr, or other similar units.

• Several days prior to the start of the PHA,

conduct a mock run to ensure all video

conferencing systems are working seam-

lessly. Keep IT help on standby to minimize

painful delays in the PHA.

• Transmit electronic copies of relevant doc-

uments to all participants a week or so in

advance of the PHA.

• One key issue that comes up during many

PHAs is: “What is the quantity of a release

or spill?” This quantity forms a basis for

assigning risk level. So, consider develop-

ing equations in spreadsheets or lookup

tables that enable quickly estimating

release quantity or rate with a reasonable

level of confidence.

• PHAs often use a risk matrix. Many such

matrices define risks rather broadly or inade-

quately, meaning estimates can differ widely.

Risk perception by different team members



ideally should match reasonably closely

— and certainly shouldn’t vary by a wide

margin. To foster team members coming up

with relatively similar estimates of risk levels,

define consequence and likelihood of events

to an adequate degree of detail.

PHA SOFTWARELarge-scale PHAs involve massive amounts of

data. Obviously, you can’t afford to use soft-

ware that crashes, responds painfully slowly,

or is hard to configure. Consider both near-

term and long-term factors. Near-term factors

include the suitability of the user interface:

ease of use; entering and editing; and import-

ing/exporting data (e.g., search, sort, save,

delete, macro functions or special short-cut

commands, templates and data transfer). It

should be relatively easy to formulate nodes,

navigate between nodes, embed the risk

matrix, track recommendations, and generate

reports and PHA statistics. Some sponsors

may not have the proposed software package.

So, it’s important to ensure they have easy

access to the PHA files. The software should

generate Microsoft Office files without requir-

ing onerous steps.

The use of a mature software package lessens

the chance of disruption. However, PHA soft-

ware continually is improving and your system

can’t afford to be static. Verify you are using

the latest version of software. If you plan to

use relatively new software, conduct several

mock runs to ensure the software package will

function efficiently. Stay away from software

in its nascent stage of development. Such

software could cause painful disruptions and

costly delays in the conduct of a PHA.

In the long-run, you want to make certain the

PHA software remains reliable and efficient.

So, assess the following:

• Vendor support. Competent technical sup-

port from the vendor is vital for ensuring

that relevant changes in data, data struc-

tures or formats can be made in a timely

manner.

• Software updates. Ideally, the upgrades

should be seamless or near-seamless.

• Longevity of company and software. Look

for a stable company that upgrades PHA

software in well-organized steps and offers

updates that are easy to install. Unfortu-

nately, determining this is easier said than

done. Acquisitions and divestitures will

continue to impact the roster of vendors.

• Continual improvement. Cloud-based sys-

tems are gaining increasing acceptance

and popularity. Regardless of where it

resides, PHA software should be capa-

ble of connecting with other programs

for health, safety, security and quality

management.

• Cybersecurity. Although the number of

cyber intrusions on industrial control and

safety systems is on the rise, PHA data

have not yet been affected. However,

appropriate safeguards against cyber

intrusions merit attention. Close working

relationships between IT and safety/secu-

rity groups will be vital.



• Effective tracking. It’s essential to know

the current status of corrective actions on

recommendations, risk status and re-vali-

dations of PHAs.

• Data analytics. There’s growing realization

that PHAs and safety functions could offer

valuable insights for improving safety if

data are analyzed carefully.

• Easy access to data. Keep track of the

compatibility of sponsors’ database man-

agement systems with the PHA software,

and make provisions so sponsors readily

and quickly can access relevant documents

in usable form.

DOCUMENT MANAGEMENTOne major issue for multisponsor PHAs is

hassle-free access to data. You must iron

out access rights and procedures during

the early stages of a project. Document

management should provide accurate and

updated data or files quickly. Generally, PHA

managers will use the existing document

system unless it’s grossly outdated. Intense

involvement by document management

professionals is crucial. Broad items to con-

sider include:

• Document integrity and security. You must

define different levels of access.

• Data inputs. The document system should

accept data in numerous forms, e.g.,

e-mails, mobile texts, scanned documents,

manual entry and bulk loads of data.

• Ease of use. Ensure all users have easy

access to review and receive printouts of

data and get update notifications.

• Collaboration. The system must provide

provisions for document routing and for

team members to collaborate.

• Alternative access. Make certain that users

still can access critical data if the primary

means (such as via the cloud) causes any

problems.

• Support. Competent document manage-

ment personnel should be available to

users quickly.

• Streamlined operation. Don’t create doc-

ument bureaucracy. Team members must

have fast access to vital information.

Remember, the focus is on risk reduction

and safety!

SAFETY LIFECYCLE MANAGEMENTRisk reduction isn’t a one-time event; it con-

tinues until the end of a project. Systems

must be in place to implement relevant

changes (management of change), docu-

ment them and update records. The safety

lifecycle is an integral part of IEC 61511/ISA

84 and its numerous revisions.

To sum up, large projects generally entail

larger risk than that of their smaller coun-

terparts. Strategic management requires

some important traits from a PHA manager

including diplomacy, patience and working

knowledge or familiarity with the PHA soft-

ware, database management and document

management systems.

GC SHAH, PE, is a senior HSE advisor at Wood, Houston.

Email him at [email protected].



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Process upsets at many chemical plants

can quickly turn dangerous. Dynamic

simulation can give engineers and

operators the power to reduce potential pro-

cess upsets or non-routine situations.

Long accepted for its strength in training,

dynamic simulation can provide additional

far-reaching value for enhancing safety. By

using a digital twin as a double for the exist-

ing process (Figure 1), dynamic simulation

offers a protected environment in which

to practice safe deployment of process

strategies and justify further safety improve-

ments. Unfortunately, myths about such

simulation (see sidebar) frequently thwart

its application.

As facilities attempt to achieve their safety

risk tolerance by performing a layers of

protection analysis (LOPA), simulation can

help determine how to improve the indi-

vidual risk factors involved in reaching the

defined tolerance. (For details on how to

avoid coincident failures in layers of protec-

tion, see “Prevent the Illusion of Protection,”

p. 21.)

A wide variety of chemical plants can ben-

efit from dynamic simulation. Here, we’ll

use examples from ammonia production.

Ammonia facilities often choose to per-

form shutdowns during process upsets

because there’s so little time, minutes at

best, to react to potentially hazardous sit-

uations. While many process plants don’t

require as aggressive a response to con-

ditions, an ammonia facility provides an

ideal environment to illustrate the value of

dynamic simulation.

Use Dynamic Simulation to Improve Process SafetyA digital twin can help spot and combat risks during design and operation

By Timothy Herbig, Bluefield Process Safety



IMPROVED RESPONSE TO NON-ROUTINE SITUATIONSResearch shows that in stressful environ-

ments, such as during non-routine and

emergency situations, operators make more

errors than under routine circumstances.

The goals of simulation include improving

safety by reducing stress and preparing

operators to perform non-routine tasks

often enough so they feel more routine.

Carrying out simulated tasks at an operator

station, as if in real life, improves response

time by invoking muscle memory in ways

that learning via pen and paper or class-

room instruction can’t.

Operator response time is a factor in a

LOPA. If performed often and well enough,

a task can be considered routine rather than

non-routine; this, in turn, could lower the

risk factor of a process area.

At an ammonia plant, a loss of feed water

can create a low level within the steam

drum, which may lead to water being

reintroduced to a hot drum, causing cata-

strophic vessel failure. In this case, during

simulation, operators might find a low level

inside the steam drum and practice imple-

menting a course of action to fix the cause,

loss of feed water.

After using dynamic simulation during train-

ing, the response of personnel becomes

more accurate and faster, thus enhancing

the independent layer of protection (IPL).

DIGITAL TWINFigure 1. An identical replica in the virtual world allows testing process changes and providing hands-on training and real-world results without affecting the actual plant.



Because the team acts safely and quickly,

the safety instrumented system (SIS) acti-

vates less.

Actually, a dynamic simulator opens up a

number of opportunities related to opera-

tor performance.

Train on a digital twin instead of the real

plant. Training on a live, working control

system is less than ideal because of risks

to the process and the associated stress in

the learning environment. By training on

a digital replica of the process — includ-

ing devices, control system, and higher

networks and systems — operators know

how to work with the system interfaces. The

simulation doesn’t affect the live process in

any way.

Create a solid baseline of performance.

Using dynamic simulation, a facility can

establish a minimum acceptable perfor-

mance for operators in given situations.

Ammonia plants, which often are located

in remote locations, usually face a short-

age of experienced operators. Simulation

enables training all operators to the same

baseline level as well as evaluating how

quickly they detect a situation, how much

DON’T FALL FOR COMMON MYTHS

Five myths too often impede the wider use of dynamic simulation:

1. Low-fidelity simulation is useless. Low-fidelity simulations aren’t exact replicas of the real

system. However, in creating a LOPA, a near replica could provide enough proof that a

person would know what to do in certain situations.

2. Simulation is just for startup. When kept current, simulations are valuable during skill

re-evaluation. For example, alarms change over time and responding to them is critical, so

keeping those current in the simulation is important.

3. Testing individual sensors and assets is enough. Facilities that don’t test assets together in

the system put themselves at risk. Simulation brings all devices together to verify, for exam-

ple, that voting works as designed.

4. Use experienced operators to train new ones. As operators perform tasks, they inadver-

tently might modify procedures. If included in training, such shortcuts can compromise

approved safe procedures. Training through simulation preserves the approved procedures.

5. Alarm hitting and tripping are the same. High-level alarms don’t necessarily need to stop the

process. With enough practice, personnel can recognize situations and be ready to respond

before a higher alarm trips and stops the process.



time they need to respond, and how

long it takes for the action to produce

results. After baselines are set, trainers

can benchmark operators over time until

tasks are performed to achieve desired

safe outcomes.

Design structured training. In an emer-

gency, each person plays a role in

de-escalating the situation. A dynamic

simulator enables the trainer at the facil-

ity to educate every operator in standard

plant procedures to execute that person’s

emergency role — and then to evaluate

the operator’s skills over time. The skillsets

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Save time during refresher training. Sim-

ulation can expedite operator review of

updated safety situations. Ammonia plant

startups have many hazardous simultaneous

activities and can benefit from, for exam-

ple, compressing tank-fill time so operators

learn skills without waiting for the fill.

Provide proof to safety evaluators. Under

many circumstances, safety evaluators that

go into a facility must weigh the soundness

of performance reviews provided to them.

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A simulator can document how opera-

tors performed during training, giving the

evaluators more confidence they have an

accurate report of abilities.

SAFE DEPLOYMENT OF PROCESS STRATEGIESPlant staff must be sure of the changes they

make to improve process safety. By com-

bining LOPA and simulation, personnel can

detect weaknesses in design and refine pro-

cess areas.

For example, while performing a LOPA on a

section of the simulated facility, engineers

might find conditions that either are unsafe

or non-optimized. Digging further into the

simulation and experimenting with designs,

they might identify ways to improve that

area of the plant.

An ammonia process can be vulnerable

to many deviations, such as low level on

jacket water or turbine over-speeds. While

these conditions themselves don’t pose a

danger to the work site, if not reacted to

properly, their consequences can injure or

kill employees who operate the process.

Personnel can safely test, via simulation,

proposed responses to ensure they do what

they should. Key in all these activities: the

live process remains unaffected until the

updates are polished and safe.

When considering dynamic simulation to

help ensure design and deployment of

safe processes, keep in mind a variety of

opportunities.

Perform alarm evaluation. A team can affect

safety meaningfully by designing an alarm

strategy that reduces, for example, nuisance

alarms so that an operator only sees signif-

icant alarms, i.e., ones that demand action.

For instance, during an ammonia plant

startup, alarms frequently are set to align

with nameplate as recommended by the

manufacturer. However, the nameplate often

eventually gets exceeded as a facility con-

tinues to improve operations and systems

through debottlenecking. Dynamic simula-

tion enables re-evaluation of potential events

in the plant environment so they cause fewer

alarms. Without simulation, that re-evalua-

tion requires a great deal of time and can fall

to the bottom of the to-do list.

Match the fidelity of the simulation to the

need. The area of the plant that most needs

improvements in safety may not require a

high-fidelity simulation. Indeed, in safety

analysis, setting the fidelity at a low level

sometimes may suffice, thus saving some

costs and time.

Conduct regression testing. With a valid

simulation of the existing process, an engi-

neering team can set up tests to compare

proposed and existing conditions to ensure

that changes won’t create unsafe condi-

tions. Using simulation, this testing can be

largely automated and easily documented



for record and compliance

purposes.

Test the SIS. By simulating

the SIS together with the

distributed control system,

a site can confirm that, if

the SIS were called upon,

the systems would act

together as they should. Or

it can see where changes

are necessary to improve

response and safety.

JUSTIFICATION OF SAFETY IMPROVEMENTSSimulation can give the

safety team tools to prove

how process or equip-

ment changes can enhance

safety, quality and produc-

tion time. Simulation also

provides an opportunity

to test the effectiveness of

safety system IPLs.

For instance, the design

team might notice that a

process change can offer

a provable four hours of

better production or save

several hours in a startup.

Further investigation might

show how to improve an

area’s safety integrity level

(SIL) rating.

An ammonia plant’s SIS

often is programmed

aggressively to shut down

the process for a variety of

situations that could, but

don’t always, pose dangers.

Although an SIS respond-

ing unnecessarily can result

in a substantial expense,

the SIS must act just in

case. Many facilities would

benefit if their teams could

realistically evaluate poten-

tially hazardous situations

before programming the

SIS to activate.

To improve safety and

avoid situations where the

SIS must activate, many

teams perform a LOPA.

Combined with dynamic

simulation, a LOPA work-

sheet (Figure 2) helps

them determine the most

effective deployment of

layers of protection. After

using simulation to analyze

the potential problems,

teams can add layers

of protection or adjust

the process to avoid the

potential problems. Then

they can re-simulate the

revised process to evalu-

ate the solutions.

Dynamic simulation can

perform a valuable role in

several ways.

LOPA WORKSHEETFigure 2. In this project, a non-routine task contributes ten times more than a routine one to the ultimate risk results.



Avoid over-engineering. A LOPA that

indicates a facility needs double redun-

dant block valves may lead to significant

over-engineering. In general, over-engi-

neered safety systems aren’t necessarily

safer; they’re just over-engineered. Simu-

lation could check, for example, whether

loss of lube oil pressure requires a SIS

response at an ammonia plant before a

facility incurs the added expense of extra

engineering and maintenance. Facilities

need the least complex systems that

implement the process safely. Simulation

can show where alternative technologies

or people, rather than systems, can handle

unique and complex tasks.

Set the IPL accurately. Simulation allows

a team to test the automation IPL and

reduce system errors. In fact, the testing

might indicate the facility has more IPLs

than required, enabling elimination of those

that aren’t needed — thus maintaining

safety while avoiding unnecessary costs.

Of course, the opposite also might occur —

testing might show the need for more IPLs,

thus saving the facility from potentially dan-

gerous conditions.

Verify human factors. A well-designed

simulator can confirm that human fac-

tors in a process and system are proper

and need no additional capital expense.

For example, does the operators’ human/

machine interface (HMI) enable them to

respond more quickly and efficiently by

giving them easy navigation and informa-

tion at their fingertips, or is it bulky and

obstructive to the point of actually reduc-

ing their effectiveness? Simulation allows

testing new systems well in advance of

their implementation and reviewing by

all interested parties rather than just

their designer.

ACHIEVE A SAFER REALITYAs the ammonia applications highlight, use

of dynamic simulation in many process sit-

uations can save time and money toward

creating a safer facility. In addition, dynamic

simulation prepares a team to go online

with fewer errors by helping them under-

stand and reduce the risks and training

them for the hazards that could happen.

As teams design the process and before

they implement the physical design,

dynamic simulation can tell them if they are

improving the LOPA results. If other design

options are on the table, the team can try

those ideas before moving ahead.

TIMOTHY HERBIG is a safety consultant for Bluefield

Process Safety, St. Louis, Mo. Email him at therbig@

bluefieldsafety.com.

ACKNOWLEDGMENT

The process simulation team at Emerson

Automation Solutions provided support and

technical information for this article.



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The Swiss cheese model familiar to

many safety professionals clearly

illustrates that when weaknesses in

barriers align, hazards can manifest [1]. If

these barriers are selected via a risk-based

methodology, the probability of failure is

calculable. Because many companies use

some type of semi-quantitative risk matrix

and require mitigation of risks to a cate-

gory level commensurate with a very low

probability of failure, multiple barriers rarely

should fail at the exact same time.

Yet, our experience in industry is that most

large consequence process safety incidents

occur due to coincidental failures of mul-

tiple layers of protection (LOPs). A likely

reason for this is that, while these layers are

assumed independent — and, thus, give the

illusion of protection — they actually aren’t

because they fall under the same manage-

ment system. A weak management system

can be a common cause of the multiple

failures.

This article examines the elements of an

integrated process safety management

system. It describes one system that can

be created and used to prevent the illusion

of protection.

WHAT IS A MANAGEMENT SYSTEM?Since the Center for Chemical Process

Safety (CCPS) issued its 20-element risk

based process safety element model, a clear

distinction has existed between process

safety and the process safety management

(PSM) regulation of the U.S. Occupa-

tional Safety and Health Administration

Prevent the Illusion of ProtectionAddress management system failings that undermine process safety

By Jerry J. Forest, Celanese

Prevent the Illusion of Protection

Address management system failings that undermine process safety

By Jerry J. Forest, Celanese



(OSHA). The former term is defined as: “A

disciplined framework for managing the

integrity of operating systems and pro-

cesses handling hazardous substances by

applying good design principles, engineer-

ing, and operating practices” and is in place

to prevent incidents [2]. The later term

refers to the rule that regulates industry.

The two shouldn’t be used interchangeably.

Similarly, PSM shouldn’t be confused with a

management system. PSM simply consists

of the 14 elements that OSHA regulates in

covered processes.

Common characteristics used to describe

management systems include a combina-

tion of people and systems, as illustrated in

Figure 1.

Weak systems executed by weak people

lead to chaos. Strong people can provide

a strong management system. However,

if that system isn’t documented, the orga-

nization will lose knowledge when people

leave. Similarly, a management system

only made up of procedures either leads

to people blindly following them without

critical thinking, or ignoring the proce-

dures. An effective management system

requires knowledgeable people executing

the necessary process safety elements

with discipline to produce repeatable

results. This type of system leads to

operational excellence and continuous

improvement.

CCPS’s Vision 20/20 describes the charac-

teristics of a vibrant management system

as “all employees must clearly understand

their role in managing process safety.”

Furthermore, the management system: “is

documented, accessible, and easily used;

defines how operations are conducted at

the workplace; promotes safety in design,

operations, and maintenance; and is agile

and continuously improved” [3].

With these characteristics in mind, a man-

agement system is: “a formally established

set of activities designed to produce spe-

cific results in a consistent manner on a

sustainable basis” [4]. Definition of these

activities is the next logical step in creating

a management system.

The past 20 years has seen the develop-

ment of several process safety models,

including those published by CCPS, the

American Chemistry Council, the American

OPERATIONAL EXCELLENCE MODEL Figure 1. People and systems both play key roles in achieving success.

Tribal Knowledge

Operational Excellence

Chaos Prescription

Peo

ple

Systems



Petroleum Institute, OSHA, the U.S. Envi-

ronmental Protection Agency and the

European Union [4]. The comprehensive

model developed by CCPS appears in

“Guidelines for Risk Based Process Safety”

[5]; it’s summarized in Table 1 and used for

discussion purposes here.

The CCPS model includes 20 elements cat-

egorized into four pillars (Table 1). These

pillars — management commitment; under-

standing hazards and risks; management of

risks; and learning from experience — make

up the key elements of an effective man-

agement system.

INTEGRATING MANAGEMENT SYSTEM ELEMENTSThe illusion of protection arises when the

various process safety elements aren’t

connected in a management system. The

selection and use of safe operating limits

(SOLs) illustrates the importance of inter-

connectivity of process safety elements in a

management system [6].

Selecting SOLs requires choosing appro-

priate process safety information (PSI) to

understand the hazards of a process. This

enables identifying high risk scenarios as a

hazard identification and risk assessment

(HIRA) process proceeds. The team might

assign SOLs to those scenarios that opera-

tor action — taking into account equipment

design and the dynamics of the process —

could prevent [7]. Once selected, the SOLs

become part of the PSI.

The SOLs then must be documented and

accessible. In addition, operators must

receive initial and then refresher training.

One way to integrate these parts of the

management system is to transfer the

information gained with PSI and HIRA to

TABLE 1. CCPS PROCESS SAFETY MODEL

Commit to Process Safety

Understand Hazards and Risks

Manage Risks

Learn from Experience

Process Safety culture Process knowledge management Operating procedures Incident investigations

Compliance with standards

Hazard identification and risk analysis

Safe work practices Measurements and metrics

Process Safety competency

Asset integrity and reliability

Auditing

Workforce involvement Contractor management Management review

Stakeholder outreach

TrainingManagement of changeOperational readinessConduct of operationsEmergency management

Its four pillars include a total of 20 essential elements.



standard operating proce-

dures (SOPs) and operator

certification/recertification

materials. Critical alarms

often accompany SOLs;

therefore, attention to alarm

management is crucial to

ensure the distributed con-

trol system’s configuration

aligns with the HIRA results.

This process should be doc-

umented. Because failure to

act on an SOL could lead to

significant consequences,

preventative maintenance

of instruments that measure

the deviations from nor-

mality deserves serious

consideration.

Auditing ensures each of

the elements described

above are interconnected

and working as intended.

The risk associated with

changes to anything in this

process must be evaluated

through a management of

change procedure. Finally,

any of these elements can

fail without the common

tie-in of management

commitment and review.

Figure 2 illustrates how

each of the process safety

management system ele-

ments are interconnected.

The management system

unites the process safety

elements. Without inte-

grating these elements, the

barriers and LOPs identified

in the HIRA only are an illu-

sion of protection. If those

LOPs aren’t considered in

building competency, doc-

umented for ease of access,

INTEGRATED MANAGEMENT SYSTEM FOR SAFE OPERATING LIMITSFigure 2. Failure to properly integrate elements can lead to the illusion of protection.

Management Commitment

Process Safety Information

Process Hazard Analysis

Operator Training

Alarm Management

Incident Reporting

Auditing

Management of Change

Standard Operating Procedures

Mechanical In-tegrity



taken into account for equipment mainte-

nance and other elements of the process

safety management system, it’s easy to

understand how this common failure mech-

anism can occur.

BUILDING A MANAGEMENT SYSTEMThere are many ways to design a man-

agement system. Companies that have

ISO certification may have management

systems documented following the Inter-

national Organization for Standardization

requirements. “Guidelines for Implement-

ing Process Safety Management” [4] also

describes how management systems

are built.

When building a management system,

adhere to some important best practices:

• Document roles and responsibilities for all

levels of the organization.

• Keep written procedures simple and

short, and include instructions and

requirements, not descriptions.

• Group similar requirements together. For

example, list all training requirements

in one document rather than dispersing

them through several.

• Include instructions in the system for

maintaining uniformity in the documents.

• Establish an approval process

for changes.

• Develop formal auditing protocols to

ensure that elements of the management

system are being followed.

With these items in mind, adopt a

three-tiered approach for the manage-

ment system.

Tier 1. In this tier, documents describe

how a company or a site does business.

For process safety, the Tier 1 document

might detail CCPS’s 20 elements of

process safety, the high requirements

for each, and how every element is

addressed. Some elements only might

have a Tier 1 requirement. This gives

individual sites or units the flexibility to

comply with the higher level requirements

commensurate with applicability.

Tier 2. Here, documents cover aspects

requiring more prescription. They describe

what is required. For example, a Tier 1

requirement might be that each process

undergoes a HIRA review once every 5

years. Because this element is essential to

understand the hazards and the risks of

a process, the Tier 2 document describes

specifics of the HIRA, such as team com-

position, methodology, minimum PSI used,

reporting and approval — to name a few.

Tier 3. In this tier, documents describe

who is responsible for what, and how

it gets done. Let’s consider, for exam-

ple, incident investigation. The Tier 1

document might mandate reporting of

all incidents. Tier 2 might have more

prescriptive requirements, such as an inci-

dent must be reported within 24 hours,



categorized (with instructions provided on

how to classify), and communicated in a

certain way. A Tier 3 document describes

who reports incidents and how they

report them. This might differ among sites

or even units at a site. (Incident investi-

gations often reveal deficiencies in Tier 3

documents that need addressing.)

Success of such a tiered management

system depends upon strong ongoing

management support. It also requires ade-

quate training for all involved, auditing for

effectiveness, and periodic management

review and continuous improvement.

FORESTALL FAILINGSThe CCPS 20-element process safety

model, if used properly, provides a basis

for effective protection against incidents.

You can’t just pick and choose portions.

Rather, the various process safety ele-

ments must share an intimate connection.

This connection is made possible by a

functioning and vibrant management

system that: “is documented, accessible,

and easily used; defines how operations

are conducted at the workplace; promotes

safety in design, operations, and main-

tenance; and is agile and continuously

improved” [3]. Without this vibrant man-

agement system, we only have the illusion

of protection.

JERRY J. FOREST is senior director, process safety,

for Celanese, Dallas. Email him at jerry.forest@cel-

anese.com.

REFERENCES1. “ANSI/API RP 754 — Process Safety Performance Indi-

cators for the Refining and Petrochemical Industries,”

2nd ed., Amer. Petr. Inst., Washington, D.C. (April 2016).

2. “Process Safety Glossary,” www.aiche.org/ccps/

resources/glossary/process-safety-glossary/pro-

cess-safety, Ctr. for Chem. Proc. Safety (CCPS), New

York City, accessed July 4, 2018.

3. “Vision 20/20,” www.aiche.org/ccps/resources/

vision-2020/five-industry-tenets/vibrant-manage-

ment-systems, CCPS, accessed July 4, 2018.

4. “Guidelines for Implementing Process Safety Manage-

ment,” 2nd ed., CCPS, John Wiley & Sons, Hoboken,

NJ (2016).

5. “Guidelines for Risk Based Process Safety,” CCPS,

John Wiley & Sons, Hoboken, NJ (2007).

6. Forest, Jerry, “Know Your Limits,” pp. 498–501, Proc.

Safety Progr. (Dec. 2018).

7. “Process Safety Glossary,” www.aiche.org/ccps/

resources/glossary/processsafety-glossary/safe-op-

erating-limits, CCPS, accessed January 8, 2018.

ADDITIONAL READING“Guidelines for Integrating Management Systems and

Metrics to Improve Process Safety Performance,” CCPS,

John Wiley & Sons, Hoboken, NJ (2016).

“Process Safety Visions, Vibrant Man-

agement Systems,” p. 55, Chem. Eng. Progr. (Jan. 2017).



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While it is not uncommon to

find shelter-in-place (SIP) or

safe-haven locations desig-

nated across chemical facilities, what varies

is the level of protection offered at these

sites. Functionality can range from merely a

muster point — a SIP — to a positively pres-

surized room — a safe haven. Either way,

when determining the room’s acceptable

performance criteria, the industry generally

applies ERPG-3 or a vulnerability factor.

An acceptable vulnerability factor often is

deemed the probability of a fatality being

less than 1%.

Emergency SIP forms an integral part of any

plant’s broader emergency response plan.

Explosions, fires and the release of smoke

or other toxic gases are some of the types

of incidents that can occur despite high

levels of planning and safety precautions.

Numerous government agencies and other

organizations recommend SIP as a measure

to reduce harm in the event of a chemical

release. Any building may be used as a tem-

porary measure to reduce health risk from

exposure to the toxic materials by simply

closing windows and doors and turning off

ventilation fans and air conditioning and

heating systems.

Three factors govern the effectiveness of a

SIP location:

• the tightness of the building or leak-

age rate,

• the concentration of the toxic gas, and

• the release duration.

Rethink Your RefugeA zero-vulnerability safe haven helps protect personnel and speed emergency response

By J. A. Rau, MineARC Systems America, LLC; A. Young, MineARC Systems, Pty Ltd; and M. McDermott, High Performance Building Solutions



The tightness of the building primarily is

based on building construction; however,

temperature differential and wind speed

also play a factor.

Identification of the maximum toxic con-

centration occurs during a facility siting

study (FSS). An FSS is a hazard analysis

that defines maximum credible event (MCE)

scenarios using a consequence-based

approach to produce a quantitative risk

assessment. Determining potential conse-

quences is a necessary step in the process

of developing a comprehensive safety plan.

The FSS determines the expected release

duration based on stored inventories

of toxic materials. The higher the toxic

concentration and longer the release

duration, the less effective sheltering in

place becomes.

While occupants may feel safe sheltering in

place from the external toxic hazard, typical

buildings have high leakage rates. A typical

wood-framed constructed building can have

three to five air changes per hour (ACH50),

rendering it ineffective against most chemical

releases. Additionally, sealing to an accept-

able airtightness can be time-consuming and

expensive. Even with professional air sealing,

it is difficult to air seal existing structures to

an acceptable tightness.

Here, we present a case study for the

conversion of five SIP spaces to 0%

vulnerability safe havens. There are con-

siderations for effectively sealing existing

infrastructure and ensuring positive

pressure to ensure contaminants do not

infiltrate safe-haven locations along with

providing the critical elements of life sup-

port, including:

• Positive pressure

• Breathable air supply

• Supplemental O2

• Removal of accumulated CO2

• Cooling and dehumidifying

INFILTRATION TESTING BACKGROUNDMineARC contracted Charlotte, North Car-

olina-based High Performance Building

Solutions Inc. (HPBS) to perform an air

infiltration study for spaces identified as

candidates to be used as SIP in the event

of an accidental chemical release. This SIP

strategy uses the existing structure and its

indoor atmosphere to separate individu-

als temporarily from a hazardous outdoor

atmosphere.

A series of pre-weatherization air leakage

tests were conducted to determine the

baseline air infiltration rate of potential SIP

spaces. Manual air sealing, a cleanroom

suspended ceiling system and low-leakage

HVAC dampers were installed to reduce the

overall air infiltration of the SIP spaces and

to close off air leakage pathways from non-

protected spaces in the building through

the HVAC system.



Post-weatherization air leakage tests were

conducted to determine the air infiltration

rate of the SIP space after the completion

of weatherization and HVAC work. The SIP

spaces additionally were air sealed using

the proprietary AeroBarrier system to

reduce infiltration rates further.

SCOPEAir sealing work was completed, and

low-leakage HVAC dampers were installed

to reduce the overall air infiltration of

the SIP spaces and to isolate the HVAC

from nonprotected spaces in the building.

Post-weatherization air leakage tests were

conducted to determine the air infiltration

rate of the SIP space after the comple-

tion of air sealing, suspended ceiling and

HVAC work.

AeroBarrier air sealing was conducted on

SIP spaces as a pilot project on September

18 through September 21, 2017, with post air

leakage tests conducted on September 21

and September 22 to determine the air infil-

tration rate of the SIP space after sealing

was completed.

Following ASTM E 779-10, pressurization air

leakage tests were conducted on the spaces

in Table 1, as recommended in the FSS.

AIR LEAKAGE TEST RESULTSPositive-pressure air leakage test results are

reported in four different ways:

• CFM4 is the quantitative volume of air

passing through an enclosure under

a pressure difference of 4 Pascals

(equivalent to a 5-mph wind). This is a

measurable physical quantity and the

value recommended in the FSS to elimi-

nate toxic gas ingress into the SIP spaces.


passing through an enclosure under a

pressure difference of 25 Pascals (0.1-

in w.g.). FEMA 453 requires Class 1 Safe

Havens be pressurized to 25 Pascals. This

is a measurable physical property.


passing through an enclosure under a pres-

sure difference of 50 Pascals (0.2-in w.g.).

• ACH50 is the quantitative volume of air

passing through an enclosure under a

pressure difference of 50 Pascals (0.2-in

w.g.) normalized by the enclosure volume.

SIP Space Occupancy Floor Area (Square Feet) Volume (Cubic Feet)

SIP Space 1 40 990 10,481

SIP Space 2 6 955 8,210

SIP Space 3 5 391 3,917

SIP Space 4 10 1,697 16,968

SIP Space 5 40 293 2,637

SIP SPECIFICATIONSTable 1. The FSS recommends SIP space testing based on these criteria.



ACH is the abbreviation for air changes

per hour. It is the number of times the air

volume in a building changes per hour at

50 Pascals of pressure.

Table 2 shows the CFM50 and ACH50 for

each of the SIP spaces pre and post-weath-

erization along with the percentage

reduction in leakage. SIP Spaces 1 and 5 did

not have pre-weatherization results as ini-

tially the whole building was tested.

Smaller spaces were selected as the whole

building was too large to feasibly convert to

a SIP space (retesting of the new SIP spaces

was not completed). The control room, SIP

Space 4, was abandoned in favor of a smaller

adjacent room due to high leakage post-man-

ual weatherization and the computers that

could not be shut down, which prevented the

use of AeroBarrier in the space.

The AeroBarrier air sealing was prescribed

a target. According to the AeroBarrier

simultaneous air leakage calculations, all the

spaces met and surpassed this airtightness

target; sealing was halted at this point.

Table 3 shows the CFM50 and ACH50

for each of the SIP spaces as tested by

HPBS post-AeroBarrier along with the

percentage reduction. The HPBS results

Safe Haven Space

CFM50 ACH50% ReductionPre-

WeatherizationPost-

WeatherizationPre-

WeatherizationPost-

Weatherization

SIP Space 1 N/A 1,871 N/A 10.7 N/A

SIP Space 2 3,623 1,560 26 11.4 57%

SIP Space 3 385 135 6 2.1 65%

SIP Space 4 N/A N/A N/A N/A N/A

SIP Space 5 N/A 655 N/A 19.4 N/A

POST-WEATHERIZATION LEAKAGE RESULTSTable 2. This table shows SIP space results according to CFM50 and ACH50 guidelines.

Safe Haven Space

CFM50 ACH50

% ReductionPost-Weatherization

Post AeroBarrier®

Post-Weatherization

Post AeroBarrier®

SIP Space 1 1,871 455 10.7 2.6 76%

SIP Space 2 1,560 182 11.4 1.3 88%

SIP Space 3 135 125 2.1 1.9 7%

SIP Space 4 N/A 173 N/A 3.3 N/A

SIP Space 5 655 138 19.4 3.1 79%

POST-AEROBARRIER LEAKAGE RESULTSTable 3. These are the post-AeroBarrier results along with the percentage reduction according to CFM50 and ACH50.



were used to calculate the

amount of positive pres-

sure required to convert the

rooms to positive-pressure

safe havens.

The AeroBarrier air seal-

ing methods improved the

air barrier integrity for all

the proposed SIP spaces

between 7 and 88% over the

post-manual weatherization

leakage rates. Air leakage

still was observed behind

many electrical penetrations,

including HVAC thermostats

and fire and smoke alarms.

These devices were covered

with plastic to protect them

from the sealant but had

hidden holes behind them.

Figure 1 displays the

post-AeroBarrier leakage

rate in comparison to the

FEMA 453 estimates for

air leakage rates based on

construction types. FEMA

453 estimates are reported

in square feet of floor area

at 25 Pascals and do not

take into consideration the

ceiling height and volume of

the space.

Figure 2 is an estimated

leakage rate based on con-

struction type to estimate

the filtration and posi-

tive-pressure system size

AIR LEAKAGE RESULTS Figure 1. This compares post-AeroBarrier air leakage rates with the FEMA 453 estimates based on construction types.

LEAK RATE ESTIMATESFigure 2. Estimated leakage rates per square foot of floor space to achieve 0.1 iwg (25Pa) overpressure by construction type.



under the FEMA 453 stan-

dard. All the SIP locations

were between tight and

typical except for SIP Room

2, which was a small prefab-

ricated metal-constructed

portable building.

Table 4 shows the combined

AeroBarrier and manual air

sealing methods improved

the airtightness for all

the proposed SIP spaces

between 68% and 95% over

the original leakage rates.

Figure 3 compares the

ACH50 pre-weatherization,

post-weatherization and

AeroBarrier air infiltration

results.

LIFE SUPPORT SYSTEMSMineARC Systems, a

refuge chamber and safety

technology company, recal-

culated the vulnerability for

each SIP space based on

the post-AeroBarrier leak-

age rates. All SIP spaces still

had a vulnerability of 100%

and therefore required the

installation of independent

life support systems to be

deemed 0% vulnerability

safe havens.

Figure 4 shows the toxic

gas concentration, dura-

tion of the release and

Safe Haven Space

ACH50

% ReductionPre- Weatherization

Post- Weatherization

Post AeroBarrier

SIP Space 1 N/A 10.7 2.6 76%

SIP Space 2 26.5 11.4 1.3 95%

SIP Space 3 5.9 2.1 1.9 68%

SIP Space 4 N/A N/A 3.3 N/A

SIP Space 5 N/A 19.4 3.1 84%

AIR INFILTRATION IMPROVEMENT FOR SIP SPACESTable 4. AeroBarrier and manual air sealing methods combined resulted in big improvements for SIP spaces.

AIR INFILTRATION RESULTSFigure 3. This figure compares the ACH50 pre-weatherization, post-weatherization and AeroBarrier air infiltration results.



vulnerability for each SIP space. As the larg-

est MCE was a full tank rupture, the toxic

concentrations were extremely high, but the

duration was short at 1 min.

The leakage rate at 4 Pascals of pressure

difference is slightly more than would

occur under a 5-mph wind used in the dis-

persion model in the FSS report based on

climatic data for the facility (to maintain

positive pressure and neutralize air infil-

tration). Post-weatherization infiltration

rates in cubic feet per minute at 4 Pascals

of pressure for each of the SIP spaces is

shown in Table 5.

The air leakage test results provide a

mathematical formula that can be used to

calculate the amount of breathable com-

pressed-air cylinders (437 ft3) that must

be added to each candidate SIP space to

maintain a 4 Pascal positive pressure to

overcome a 5-mph design wind coincident

with a toxic release.

MineARC Systems was contracted to

install life support systems to convert

the SIP spaces to positive-pressure safe

havens. The MineARC AirBANK pos-

itive-pressure system provides rapid

pressurization, which is activated and

maintained using the AirBANK Control via

a simple human-machine interface (HMI)

touch screen.

MineARC’s integrated Aura-FX Gas Mon-

itor ensures breathable air automatically

remains within acceptable limits. Addi-

tionally, the installation of supplementary

oxygen and carbon dioxide scrubbing sys-

tems in safe havens are as needed.

SIP SPACE VULNERABILITY Figure 4. A tank rupture appears as the worst-case scenario but of a short duration.

Safe-Haven Space Volume (Cubic Feet)

CFM4

SIP Space 1 10,481 99

SIP Space 2 8,210 32




AIR LEAKAGE RESULTS AT CFM4Table 5. SIP space post-weatherization infiltra-tion rates using AeroBarrier is shown.



Figure 5 shows the number of 437-ft3

cylinders required for each safe-haven

location. The minimum breathable air per

person is 2.5 cfm (70L/min) per person

based on MineARC’s experience and test-

ing within the refuge chamber industry.

The maximum CO2 concentration is at 1%

and O2 between 19.5 and 23.5% based on

Occupational Safety and Health Administra-

tion (OSHA) limits. Because of the volume

and number of people in Safe Haven Space

5, it required supplemental oxygen and

carbon dioxide scrubbing to maintain the

internal gas concentrations within specified

limits (Figure 6). Three sodium chlorate

oxygen candles and two AirGEN CO2 scrub-

bers were included in the design.

In 2018, MineARC completed installa-

tion and training on the five safe-haven

spaces. Each safe haven was tested

during the commissioning process to

ensure it could maintain acceptable posi-

tive pressure.

CONCLUSIONSThe conversion of SIP locations to 0%

vulnerability safe havens is a three-step

process consisting of the following:

1. Identification of the correct SIP loca-

tion based on ease of sealing and

small volume based on the required

occupancy,

2. Manual and AeroBarrier air sealing of

SIP spaces,

3. Installation of life support equipment.

INTERNAL GAS CONCENTRATIONS IN SAFE HAVENSFigure 6.Additional supplemental oxygen and carbon dioxide scrubbing may be needed to maintain the internal gas concentrations within OSHA limits.

QUANTITY OF CYLINDERS REQUIRED FOR 4PA POSITIVE PRESSUREFigure 5. Based on how much air each person would need to breath, this figure shows how many cyl-inders would be needed in a chamber.



Identifying SIP spaces that can seal from

the outset is crucial to a successful result.

In the case study, three of the five original

locations were abandoned in favor of rooms

in adjacent locations because of high leak-

age rates or reducing the size to make the

project more cost-effective. Control rooms

are the most difficult to seal because of

the false floor and myriad cable trays and

pass-throughs installed for the computer

systems. The smaller the room and the

more robust the construction (i.e., prefab-

ricated metal or concrete buildings), the

better it seals.

REFERENCES

ASTM E779-10, “Standard Test Method for Deter-

mining Air Leakage Rate by Fan Pressurization,”

ASTM International, West Conshohocken, PA,

2019, www.astm.org

Brake, Fellow, & Bates (1999). “Criteria for the

design of emergency refuge stations for an under-

ground metal mine.” Aus. IMM Proceedings, No.2,

1999, pp 1–7.

Department of Mines and Petroleum, 2013,

“Refuge chambers in underground mines — guide-

line: Resources Safety,” Department of Mines and

Petroleum, Western Australia, 41 pp.

Epstein, Y., & Moran D. (2006). Thermal Comfort

and the Heat Stress Indices, Industrial Health, 44,

388–398.

FEMA 453. (2006). “Design Guidance for Shelters

and Safe Rooms,” Federal Emergency Manage-

ment Agency

Health & Safety Executive UK (2008). “Guidance

and Information on the role and design of safe

havens in arrangements for escape from mines,”

www.hse.gov.uk/pubns/mines08.pdf

ITA Working Group 5 (2016). “Provisions for

refuge chambers in tunnel projects under con-

struction,” ITA Report N°014 - V2 / March 2018.

Mines Safety and Health Administration (2008).

30 CFR Parts 7 and 75 “Refuge Alternatives for

Underground Coal Mines; Final Rule.”

National Institute for Occupational Safety and

Health (2007). “Research Report on Refuge

Alternatives for Underground Coal Mines,”

www.cdc.gov/niosh/docket/archive/pdfs/

NIOSH-125/125-ResearchReportonRefugeAlterna-

tives.pdf.

Occupational Safety & Health Administration

(2013). “Permit-required confined spaces,” www.

osha.gov/pls/oshaweb/owadisp.show_docu-

ment?p_table=STANDARDS&p_id=9797

Suming Du. (2014). “On the effectiveness of shel-

ter-in-place as a measure to reduce harm from

atmospheric releases,” Journal of Emergency Man-

agement, Vol. 12, No, 3, May/June 2014.

Venter. J. (1998). “Portable Refuge Chambers:

Air or Tomb in Underground Escape Strategies,”

School for Mechanical and Materials Engineering,

Potchefstoom University, Republic of South Africa.

Worksafe Australia National Standard (2005).

“Australian Standard AS: NZS 1716:2003 Respira-

tory protective devices.”

Yantosik. G. (2006). “Shelter-in-Place Protective

Action Guide.” The Chemical Stockpile Emergency

Preparedness Program (CSEPP). U.S. Department

of Energy



Manual air sealing needs to be overseen by

someone with familiarity in building tight-

ness. While most of the tasks are general

construction, standard contractors are not

trained to work at the level of precision

needed to ensure proper sealing. Even a

tiny orifice or ceiling tile not sealed cor-

rectly can ruin a leakage test result.

For future construction projects, incorpo-

rating SIP spaces should occur during the

design phase. Air barrier commissioning is

standard in new construction and should

include the following tasks at a minimum:

• Design review of the plans with specifi-

cations for the air barrier and mechanical

system — specifically as they relate to

spaces designated for use as safe havens;

• Quality assurance inspections during

construction to ensure a continuous air

barrier is in place; and,

• Final air leakage testing of the continuous

air barrier to ensure the leakage rate of

the safe haven spaces are within accept-

able limits.

Complementary life support equipment

is essential to sustain life within an air-

tight environment. For personnel to

remain within the sealed safe haven, the

environment must be habitable. Air is to

be free of toxins such as carbon dioxide,

and acceptable levels of oxygen must be

maintained.

Positive-pressure systems reduce the ingress

of toxins and provide some or all of the

required source of breathable air. Additional

equipment such as compressed air, oxygen

cylinders and air scrubbers are used to meet

the shortfall. Furthermore, internal conditions

must consider the human condition, support-

ing workable body temperature and humidity.

Reducing the risk of harm to personnel is a

priority for emergency response planning.

While the likelihood of an MCE occurring

may be low, the risk to on-site personnel in

the event of an incident is high. Convert-

ing SIP locations to zero-vulnerability safe

havens improves emergency response.

J. A. RAU is general manager at MineARC Systems

America, LLC, and can be reached at James.Rau@min-

earc.com. ASHLEE YOUNG is marketing coordinator

at MineARC Systems, Pty Ltd and can be reached at

[email protected] MEGHAN MCDERMOTT

is the owner and architectural engineer of High Per-

formance Building Solutions. Email her at meghan@

hpb-solutions.com.



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Natural gas processing plants are

complex facilities designed to

separate natural gas composed

almost entirely of methane from other

hydrocarbons, nitrogen, water, metals and

other impurities. These plants are usually

located in natural gas processing regions

and connected to wellheads through a

network of small-diameter, low-pressure

gathering pipelines. Natural gas plants’

main hazard are fires and detonations and

acute exposure to toxic gases from uncon-

trolled releases of flammable and toxic

materials. The large inventories of flamma-

ble and toxic gases and liquids managed

by these plants combined with the high

density of equipment and relatively large

occupancy rates speak to their high

hazard potential.

The dangers of gas plants are underscored

by the severity of accidents that can occur.

On June 27, 2016, for example, loss of con-

tainment from a heat exchanger led to the

release of methane, ethane, propane and

other hydrocarbons at the Enterprise Prod-

ucts Pascagoula gas plant in Pascagoula,

Miss. (CSB 2019). The leak led to a large-

scale fire and explosion. A similar incident

occurred on September 25, 1998, when a

heat exchanger in the Esso gas plant in

Longford, Victoria, Australia, ruptured,

releasing hydrocarbon vapors and liquids

(Kletz 2009). As with the Enterprise Prod-

ucts incident, the escape resulted in a large

fire and explosion.

Natural gas plants are critical infrastruc-

ture for the modern energy supply and

Ensure Reliable Fire Protection in Natural Gas PlantsCombustible and toxic gas detectors as well as flame detectors can help reduce incidents.

By Edward Naranjo, Emerson



their safety is of utmost importance. In the

United States, natural gas plant operators

must follow process safety management

regulations for general industry (29 CFR

1910) as well as several of the state plans

approved by the Occupational Safety and

Health Administration. Guidelines like API

Bull 75L and process safety standards like

IEC 61511 offer the framework for man-

aging process safety systems through

their lifecycle.

In the following sections, we will review

provisions for protection of natural gas

processing facilities and illustrate their use

through several examples of common pro-

cess modules. We will then address the

interface between fire and gas detectors

and the control systems that manage the

plant. Fire and gas systems are in effect the

independent layer of protection that drive

mitigation actions to arrest the escalation

of accidents. In consequence, it is important

NATURAL GAS PROCESSING FLOW DIAGRAMFigure 1. Natural gas processing plants are complex facilities designed to separate natural gas com-posed from other hydrocarbons, nitrogen, water, metals and other impurities.



to survey how instruments and logic solvers

contribute to improving the performance of

the combination.

PROVISIONS OF FIRE AND GAS SYSTEMSNatural gas processing consists of sepa-

rating several hydrocarbon molecules and

contaminants from pure natural gas. The

process includes condensate and water

removal, acid gas removal, dehydration,

mercury removal, nitrogen rejection, and

natural gas recovery, separation, and

treatment. Many associated hydrocarbons

known as natural gas liquids are valuable

products of the separation of natural gas;

when components are separated and frac-

tionated, their feedstocks are sold to oil

refineries, petrochemical plants and oil pro-

ducers for a variety of uses. A schematic

flow diagram of a natural gas processing

plant is shown in Figure 1 (Riazi et al. 2013).

Process units incorporate some degree of

protection in the form of fixed point and

open path gas detection. Because raw nat-

ural gas contains components with higher

and lower molecular density than air, detec-

tors in several process units must be placed

at both floor and ceiling level where gas

may fractionate. Open path detectors may

be used to protect module boundaries,

particularly where heavier-than-air combus-

tible fluids are managed, and the process is

relatively close to the perimeter and disper-

sion modeling indicates that small, but high

probability releases may cross the fence line

and the sources of such releases are outside

the coverage or at the limits of point detec-

tion. Point and open path hydrogen sulfide

(H2S) detection are required in acid gas

removal and the sulfur recovery unit, and

similarly, at the gas well during production

of hydrocarbon fluids and condensates and

water removal.

In general, it is impractical to provide toxic

gas detectors to address every toxic release

scenario in most process facilities. As a

result, the use of fixed detectors is limited

to target receptor monitoring and high-risk

applications. Point detectors are placed

on grid spacing and near points of entry

and along normal travel paths of travel

within the units, especially in those loca-

tions where personnel may not be able to

observe the area as they approach potential

release sources. Open path H2S detectors

are beneficial between equipment in toxic

service and mustering points and between

potential release sources and uncontrolled

areas like service roads and parking lots.

The UK Health and Safety Executive (HSE)

has alerted about the dangers of oil mist in

offshore gas turbines (HSE 2008). When

liquid sprays impinge on hot metal surfaces,

they may ignite as the surface temperature

exceeds the liquids’ autoignition tem-

peratures. In the same fashion, lubricating

systems in gas compressors in gas plants

are at risk of fires if not protected. Oil mist



detectors should be installed near compres-

sors and lubricating and hydraulic systems.

Likewise, for glycol dehydration and natural

gas liquid extraction using the absorption

method, best practice calls for installing oil

mist detectors near high pressure sources

of liquid leaks.

Ultrasonic gas leak detectors are applied in

all outdoor locations with pressurized pipe-

work. Locations include compressor areas,

filter stations, separators, gas metering

skids and receiver areas.

Flame detectors should view all modules

and all major items of the plant. A common

arrangement is to locate detectors at the

corners of an area or module such that the

detectors’ field of view covers areas where

fires may occur. Computer aided design

tools should be used to optimize area

coverage at the design stage. To increase

detection effectiveness, no area should be

completely dependent on a single device.

Figure 2 illustrates flame detectors on an

absorption tower and reboiler.

Because of their long-range capability and

wide field of view, multispectral infrared

flame detectors offer optimum performance

for these applications. Flame detectors

should be used with combustible gas detec-

tors to safeguard plants against fires and

explosions. As the HSE has shown in the UK

INSTALLATION IN DEHYDRATION PROCESSING UNITFigure 2. Two flame detectors are used to monitor the area around an absorption tower and reboiler.



offshore sector, combustible gas detection

equipment is not 100% effective in open

installations (McGillivray and Hare 2008).

The likelihood of credible gas releases

escalating into incidents that could cause

large-scale damage is much diminished

when flame and combustible gas detectors

work in tandem. In the next section, we’ll

examine some common arrangements of

these devices in process modules.

SEPARATOR AREASeparator process modules include the

separator, heat exchanger, and gas cooler.

Figure 3 shows an ideal arrangement. Point

gas detectors are placed between the

separator and heat exchanger, under the

coolers, where gas may accumulate. Two

open path detectors are placed on oppo-

site sides of the process module to provide

area monitoring consistent with the prev-

alent wind direction. For fast response to

pressurized gas releases, ultrasonic gas leak

detectors are positioned to cover potential

leak sources like flanges and valves on the

separator and coolers. To avoid shadow-

ing and reflections, gas leak detectors are

placed on either side of the cooler, while

flame detectors are installed at the cor-

ners and between the separator and heat

exchanges to view most of the module.

A cluster of devices as shown may be

interfaced with a logic solver installed in

a control room. To reduce wiring and the

control system’s footprint, a distributed

FLAME AND GAS DETECTORS AND CONTROL SYSTEM IN SEPARATOR AREAFigure 3. A distributed I/O block can be placed near the process module to help reduce wiring and the control system’s footprint.



I/O block can be placed near the process

module also shown in Figure 3.

METERING SKIDMeasurement of process fluids being

transferred to other plants takes place in

metering skids. The primary variable to

be measured is mass flowrate. Main com-

ponents include the structure frame and

supports, pipework, process equipment

like flowmeters and process gas chro-

matographs, and local control system. For

illustration, we’ll assume the process fluid is

pipeline quality dry natural gas. As shown

in Figure 4, an ultrasonic gas leak detector

covers the footprint of the metering skid.

Depending on size and degree of obstruc-

tion, one or several flame detectors may

be necessary to supply adequate area

coverage for the skid. In this example, two

detectors are placed on opposite corners.

A distributed system offers an elegant

approach for managing field devices in a

metering skid installation. A distributed I/O

block, for example, can interface with flame

and gas detectors for one or several meter-

ing skids in proximity, an arrangement that

offers the benefits described in the previ-

ous section.

PACKAGED FIRE AND GAS SYSTEMFire and gas systems in gas plants are no

ordinary equipment. Because gas plants

are located near exploration and produc-

tion facilities, logic solvers may be exposed

to adverse conditions like high humidity,

brine, high vibration, and voltage variations.

FLAME AND GAS DETECTORS IN NATURAL GAS METERING SKIDFigure 4. An ultrasonic gas leak detector covers the footprint of the metering skid.



Not surprisingly, printed circuit boards are

weatherized by application of conformal

coating and wires and other electronic

components are designed to allow for few

common failures. Compared to other con-

trollers, a fire and gas system logic solver

incorporates redundant power and commu-

nication paths for input and output devices

and must easily integrate with safety instru-

mented and emergency shutdown systems

to which they may pass certain demands.

Certifications also play a critical role for

fire and gas systems in gas plants, because

these address minimum requirements for

product performance, reliability and sur-

vivability. In the United States, fire and gas

systems are installed according to NFPA 72

and certified to performance standards like

FM 3010 and UL 864. Similarly, the system

level standard for Europe is EN 54-2.

One of the most important differences

between personal computers and industrial

logic solvers is the design of the latter as

complete packages. In logic solvers, software,

hardware, and documentation are designed

and tested to work together. Similarly, fire

and gas systems are designed to meet per-

formance standards that link the size and

nature of the hazards to the characteristics of

the system and ensure requirements are met

for operation and availability. Such packaged

solutions offer several benefits to natural

gas plants. To begin, the performance of the

complete system, from a selected group of

initiating devices to notification appliances

and other fire outputs is defined and limits

and exceptions are known. Surprises during

installation commissioning, and operation are

kept to a minimum. In addition, packaged

solutions are equipped with configuration

libraries that facilitate the automatic com-

missioning and documentation of several

devices at a time. As mentioned above, gas

plants can have several hundred or thousand

flame and gas detectors and other peripher-

als associated with fire and gas monitoring,

resulting in numerous weeks of installation

and commissioning for manual or sequen-

tial set up, an approach that is also prone to

error. In one instance, smart commissioning

with pre-loaded field device settings resulted

in a significant reduction of commissioning

cycle time.

The profit to be gained from packaged

systems extends well beyond commis-

sioning. It is well known that real-time

HART integration into system architecture

enables users to get access to diagnostics

and configuration information. Continu-

ous communication between field devices

and control system allows problems with

the device to be detected within seconds,

enabling action to avoid process disruptions

and unplanned process shutdowns. Regret-

tably, many end users have no access to

such information. Unlike field devices for

process control, flame and gas detectors

make use of analog output values below 4

mA to report faults. Values of 1, 2 and 2.5



mA to denote informational or critical faults

are not uncommon. Table 1 illustrates some

common diagnostics available in a few

commercial models and their corresponding

analog output levels.

For field devices equipped with HART, the

FieldComm Group specifies a minimum

analog current signal of 3.5 mA. As a result,

end users wishing to take advantage of

diagnostics, process variable, and con-

figuration information available through

HART must program logic solvers to read

values below the HART limit. The process

is time consuming because every model’s

specific range of analog output levels and

configurations must be considered. Even

if some controllers allow access to HART

commands with analog output values

below 3.5 mA, device specific commands

may be suppressed. Invariably, ensuring

the device meets the design safety intent

requires additional programming and test-

ing, often after installation. Compare such

an approach to one of a packaged pre-engi-

neered system. By design, with a packaged

Table 1. This list includes several Rosemount flame and gas detectors, as well as their common diagnostics and corresponding analog output levels.

Fault Condition Product Model(s) Analog Output (mA)

Input voltage less than 8 VDC Gas Transmitter 2.5

Input voltage more than 33 VDC Gas Transmitter 2.5

Critical memory fault Gas Transmitter 2.5

Onboard power supply fault Gas Transmitter 2.5

Sensor zero drift Toxic Gas Sensor 2.5

Memory fault Toxic Gas Sensor 2.5

Calibrate sensor Toxic Gas Sensor 2.5

Span calibration failure Combustible Gas Sensor 2.5

Zero calibration failure Combustible Gas Sensor 2.5

Sensor over-range Combustible Gas Sensor 2.5

Low temperature Combustible Gas Sensor 2.5

High temperature Combustible Gas Sensor 2.5

Replace sensor Combustible Gas Sensor Momentary 2.5 mA

Memory fault Combustible Gas Sensor 2.5

Power supply fault Combustible Gas Sensor 2.5

Sensor nearing end of life Combustible Gas Sensor Momentary 2.5 mA

Sensor weak signal Combustible Gas Sensor Momentary 2.5 mA

Fault Flame Detector 1.0

Dirty window Flame Detector 2.0

Sensor test fault Ultrasonic Gas Leak Detector 2.0

Internal process fault Ultrasonic Gas Leak Detector 1.0

Major fault Ultrasonic Gas Leak Detector 0

SAMPLE FAULT ANALOG CURRENT LEVELS



solution pertinent commands are tested for

every HART field device within the scope

of the certification. The need for custom

programming is reduced, which helps keep

system implementation on schedule.

Finally, pre-engineered systems enable more

efficient alarm management. When an assort-

ment of field devices and control systems

which have not been tested together are first

integrated, the diversity of alarms and alerts

that must be managed can be overwhelm-

ing. Which action should be undertaken if a

device reports a low line voltage fault? Can

it continue to operate under low voltage

for several weeks or is it unable to perform

its protective function? Although standards

for alarm management like ANSI/ISA-18.2

specify rankings for diagnostics, the termi-

nology, what constitutes an alarm, and what

is critical for a device’s safe operation varies

considerably by vendor. Making sense of the

diversity falls on the end user, which must

rationalize alarms through trial and error. At

one extreme, all diagnostics are suppressed,

putting an end to improved asset utilization,

while at the other alarm flooding is likely to

occur. With pre-engineered systems, much

of the trial and error related to alarm ratio-

nalization is minimized. Rank ordering of

diagnostics and level of criticality is consis-

tent across field devices. In consequence,

implementations are not only faster but the

plant also benefits from fewer abnormal sit-

uations and decrease of capital equipment

for repairs.

CONCLUSIONNatural gas plants are critical infrastruc-

ture for natural gas supply. Although

some separation of water, metals, and

other impurities from raw natural gas

takes place at wells, natural gas process-

ing facilities carry out most of the steps to

separate natural gas liquids into feedstock

for oil refineries and chemical plants and

produce pipeline grade natural gas. Due

to the potential for accidental release of

hazardous chemicals, natural gas plants

face severe risks. Fires and explosions

and acute exposure to toxic gases and

asphyxiants can disrupt operations and

cause harm to the workforce and any

surrounding population. Fire and gas sys-

tems protect these plants by reducing

the consequences of incidents. Minimum

provisions for fire and gas systems include

the installation of combustible and toxic

gas detectors and flame detectors. As

shown in the two examples above, the

ideal arrangement of these devices varies

across process modules based on the

nature, location and severity of the poten-

tial hazard.

Fire and gas systems for natural gas

plants must be reliable. Due in no small

part to the risk of business disruption,

process facilities have instituted tougher

safety practices including more safety

instrumentation and layers of protec-

tion. System hardware and software are

designed for adverse environments and



the systems themselves are certified under

performance standards for adequate

availability and survivability. Distributed

I/O configurations contribute to reducing

the footprint of these systems, enabling

operators to integrate devices over long

distances at reduced costs compared to

conventional peer-to-peer networks.

For operators seeking to deploy or

modify a fire and gas system, packaged

safety solutions offer significant bene-

fits. Smart commissioning, ready access

to configuration and diagnostic informa-

tion through HART and rank ordering of

alarms out of the box reduce the need for

custom programming and testing, which in

turn leads to faster implementations and

reduced maintenance costs.

EDWARD NARANJO is director of fire and gas sys-

tems for Emerson’s Automation Solutions business.

He is an ISA Fellow and certified functional safety

engineer with 16 years of experience in flame and

gas detection. Edward may be reached by e-mail at

[email protected].

REFERENCESANSI/ISA-18.2, Management of Alarm Systems

for the Process Industries. 2016. Research Trian-

gle Park, NC: ISA.

API Bull. 75L, Guidance Document for the

Development of a Safety and Environmental

Management System for Onshore Oil and Nat-

ural Gas Production Operations and Associated

Activities. 2007. Washington, DC: API.

CSB. 2019. Loss of Containment, Fires, and

Explosions at Enterprise Products Midstream

Gas Plant, Pascagoula, Mississippi, No. 2016-02-

I-MS. Washington, DC: U.S. Chemical Safety and

Hazard Investigation Board.

EN 54-2, Fire Detection and Fire Alarm Systems,

Part 2: Control and Indicating Equipment. 2006.

Brussels, Belgium: European Committee for

Standardization (CEN).

FM 3010, Approval Standard for Fire Alarm Sig-

naling Systems. 2014. Northwood, MA: FM.

HSE. 2008. Fire and Explosion Hazards in Off-

shore Gas Turbines: Offshore Information Sheet

No. 10/2008. Aberdeen, UK: HSE.

McGillivray A. and Hare, J. 2008. Offshore

Hydrocarbon Releases 2001 – 2008 (RR672).

Buxton, Derbyshire, UK: HSE.

IEC 61511, Functional Safety: Safety Instru-

mented Systems for the Process Industry

Sector (2nd Ed.). 2016. Brussels, Belgium:

European Committee for Standardization

(CEN).

Kletz, T. 2009. What Went Wrong? Case His-

tories of Process Plant Disasters and How They

Could Have Been Avoided (5th Ed.). Amster-

dam, The Netherlands: Elsevier.

NFPA 72, National Fire Alarm and Signaling

Code. 2019. Quincy, MA: NFPA.

Riazi, M. R., Eser, S., Peña Díez, J. L., and

Agrawal, S. S. 2013. Introduction. In Petroleum

Refining and Natural Gas Processing, eds. M.

R. Riazi, S. Eser, J. L. Peña Díez, S. S. Agrawal.

West Conshohocken, PA: ASTM International.

UL 864, Standard for Control Units and Acces-

sories for Fire Alarm Systems (10th Ed.). 2014.

Chicago, IL: UL.



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