Safety Systems for Non-Engineers

Aug. 7, 2009
What All the Hullabaloo Over Safety Instruments Systems Is About?

By Dave Harrold

Does this describe you?

Your job is to make informed business decisions. You understand the role of process control systems; you understand the role of safety instrumented systems, but you want a better understanding of safety instrumented system jargon and requirements, and you need to be able to explain safety instrumented systems to your boss
If so, keep reading because this article is for you.

Does this sound familiar?

The following conversation is taking place at the Springfield Snacks and Pesticides Plant between plant manager Mr. Montgomery Barns and supervisor of safety, Gomer Himpson. Let's listen in.

Gomer: Good morning Mr. Barns; how is your day going so far?

Mr. Barns: It's not a good morning when I see you, Himpson.

Gomer: You recall a few months ago that I told you our safety instrumented systems were due for a review?

Mr. Barns: I know that you annoy me about something every month.

Gomer: Well I got with Carl, Charlie and Lenny, and we went through our SIS with a fine-tooth comb. We did a HAZOP and a LoPA and found several of our SIFs were improperly assigned to SIL 1 when they should be SIL 2. We also found a few SIL 2 SIFs that could qualify as SIL 1s, but since we've always maintained diversity among our SIS logic solvers we can't just reclassify these SIFs. We did a preliminary look at the PFD of a few of these SIFs, and we think there is something we can do in the BPCS. Also Mr. Barns, ever since corporate insisted on extending the time between scheduled shutdowns, it is playing havoc with our full- and partial-stroke testing periods. Mr. B. I know I don't have to tell you how OSHA feels about IEC 61511 and IEC 61508. What would really be helpful is if we replaced our old SIS with one from the same vendor as our BPCS; that way everything would be "smart." Of course, that means we really need to install exida- and/or TÜV-certified sensors and final elements.

Mr. Barns: STOP! Have you lost your wits Himpson? You're talking in gibberish and everyone knows that the word "smart" should never be uttered by your lips.

So what do you think? Did Mr. Barns have a clue what Gomer was talking about? Would you? As ridiculous as it probably sounds right now, everything Gomer said made sense, but only if you have some knowledge of the jargon.

During the next few minutes we are going to dissect what Gomer was saying, and we'll also take a look at what it means in terms of safer processes.

". . .went through our SIS"

"I got with Carl, Charlie and Lenny and we went through our SIS with a fine tooth comb."

SIS is an acronym for Safety Instrumented System and is defined in safety standards as, "instrumented system used to implement one or more safety instrumented functions. An SIS is composed of any combination of sensor(s), logic solver(s) and final elements."

That definition provides some help, but let's look a bit closer at this SIS thing.

SIS logic solvers use the input provided by the sensors and execute the program logic that eventually results in an automated emergency shut-down. For example, a 1oo2 (read as one-out-of-two) logic design monitors two inputs. If either of those inputs changes states, the logic solver executes the shut-down sequence. A 2oo2 logic design uses two inputs, and both must agree in order for the logic solver to initiate the shut-down. There are a number of different design types, 1oo1, 1oo2, 2oo2, 2oo3, etc., and it is quite common to mix analog and discrete inputs. This is called using diverse technologies, and it is very useful in eliminating "false or nuisance" shut-downs resulting from common-cause failures.

SIS final elements are the pumps, motors, on/off valves, sometimes throttling valves, etc., that actually stop, close open, or whatever actions are necessary to bring the process to a safe shut-down state.

What Gomer was explaining to Mr. Barns was that he, Carl, Charlie and Lenny had conducted a through audit of the entire SIS―every sensor, logic solver and final element ―in order to compare what was installed and how it was done with what had originally been designed and specified.

Note: A communications network may or may not be a part of the SIS. If the logic solver uses some form of a communications network to connect with the inputs and/or outputs, then that communication network is part of the SIS, and thus becomes subject to all the design and testing requirements of the SIS. However, if the logic solver uses a communication network to connect to a non-safety controller and/or an operator interface, then that communication network is not part of the SIS.

Do not think that every safety application requires a microprocessor-based logic solver. It is still perfectly legitimate to use relays and stand-alone technologies. In fact, there may be situations that justify using a relay or stand-alone system alongside a microprocessor- based solution. Just be sure they remain separate and independent of one another.

…Did a HAZOP, LoPA, …"

"We did a HAZOP and an LoPA and found several of our SIFs were improperly assigned to SIL1 when they should be SIL 2."

The definitions of HAZOP and LoPA have been around a long time and are not confined to SIS discussions. Most companies have been conducting HAZOP and LoPAs for several decades.

HAZOP is short for HAZards and OPerability studies (analysis). HAZOPs are systematic methods used to examine complex facilities or processes in order to find ways to improve operational performance and potentially hazardous situations. It's noteworthy that about 60% to 65% percent of a typical HAZOP study focuses on the operability-related opportunities to improve product quality and overall operational performance.

LoPA is short for Layer of Protection Analysis. It is a simplified form of risk assessment that is often used as an extension to or in conjunction with other process hazard analysis methodologies. LoPA considers the different and diverse hazard mitigation "layers" available. For example, two layers of protection typically provided for holding tanks is 1) an automated overfill protection system and 2) locating the tank inside an enclosed dyke or berm area.

SIF (Safety Instrumented Function) is defined in safety standards as a "safety function with a specified safety integrity level which is necessary to achieve functional safety and which can be either a safety instrumented protection function or a safety instrumented control function." That's really not much help.

To really understand and appreciate the nuances of the SIF will require some additional homework on your part, but for now accept that the SIF is the safety loop equivalent of a single process control loop―something akin to a flow, pressure, level or temperature control loop. But instead of controlling level to an operator determined setpoint, the SIF (safety loop) monitors for a pre-determined unsafe condition (i.e., high level) and automatically initiates the appropriate action necessary to mitigate the unsafe condition.

SIL (Safety Integrity Level – see table) is defined in safety standards as a, "discrete level (1-4) for specifying the safety integrity requirements of the safety instrumented functions to be allocated to the safety instrumented systems. Safety integrity level 4 has the highest level of safety integrity; safety integrity level 1 has the lowest."
SIL values are assigned to each SIF using a systematic methodology, such as LoPA.

Note: When the SIS logic solver is microprocessor-based (i.e., DeltaV SIS, Triconex, GE Fanuc, Allen-Bradley GuardLogix, Honeywell Fail Safe, etc.) it will very likely host multiple safety loops (SIFs) with different SIL value assignments.

Even among experienced safety system practitioners, SIL assignments are often misunderstood. Concern often arises when an identified risk is assigned a SIL 3 value. What some people have overlooked is a small footnote in the safety standard that permits dividing the mitigation of a risk across multiple SIL values. For example, rather than incur the life-cycle costs associated with a single SIF (safety loop) classified as SIL 3, you are permitted to split the SIF into "mini-functions" meaning you may, for example, implement both a SIL 1 and a SIL 2 solution for that particular risk and still meet the SIL 3 requirements.

What Gomer was explaining to Mr. Burns was that he and his buddies had systematically examined the hazards using two independent methodologies (HAZOP and LoPA) and had found that several of the safety loops (SIFs) were not assigned the correct risk reduction values (SIL), thus the plant's safety instrumented system (SIS) wasn't providing the level of protection expected or needed.

Good news & bad news

"We also found a few SIL 2 SIFs that could qualify as SIL 1s, but since we've always maintained diversity among our SIS logic solvers, we can't just reclassify these SIFs."

It sounds like Gomer is talking in circles, but he really isn't.

What Gomer is telling Mr. B. is that a few of the safety loops (SIFs) were originally designed and are now being operated, and maintained as SIL 2 (risk reduction 100 to 1000) when in fact the risk is not very severe, so a few SIFs could be designed, operated, and maintained as SIL 1 (risk reduction 10 to 100).

Gomer's good news is that the company is spending more money to operate and maintain these improperly assigned safety loops than is necessary. Gomer's bad news is that there is a safety instrumented system (SIS) logic solver for each SIL value (diversity) – "…we've always maintained diversity among our SIS logic solvers..." – meaning there is a logic solver that hosts all the SIL 1 safety loops, another logic solver that hosts all the SIL 2 safety loops, etc. In order for the Springfield Snacks and Pesticides Plant to maintain its logic solver diversity practice requires physically moving each reclassified SIF―wiring, program logic, documentation, etc.―from one logic solver to another.

Gomer's implication is that this requires some serious change control procedures and follow-up testing of both logic solvers to ensure each is working properly after all the changes have been completed.

Note: Safety standards do permit different SIL-valued safety loops to reside in the same logic solver. However, doing so means that the logic solver must always be designed, operated and maintained per the requirements of the highest-valued SIL safety loop residing in that logic solver.

A frequently overlooked footnote in the IEC 61511-1 safety standard is Note 2 of paragraph 3.2.74 which says, "It is possible to use several lower safety integrity level systems to satisfy the need for a higher level function (for example, using a SIL 2 and a SIL 1 system together to satisfy the need for a SIL 3 function)."

A common application of this concept often occurs in reactor designs where there is a need to prevent reactor run-away. You can design a single SIF that will likely be classified as SIL 3; OR you can design two SIFs, each with lower SIL values.

In choosing the second option, the first SIF is designed to close/open valves, stop/start pumps, etc., bringing the process to a safe state. The second SIF is designed to inject a "kill" solution (chain-stopper) into the feed stream. If one of these SIFs achieves a SIL-1 risk-reduction value, which is easy to achieve, and the other a SIL 2 risk-reduction value―not very difficult to achieve―then when combined, the two designs provide the same risk-reduction as a single SIL-3 design. However, and here's the best part, both SIFs can likely be cost effectively designed to achieve a SIL-2 risk-reduction value, thus producing an overall more reliable solution without incurring the life-cycle cost typically associated with a single SIL-3 design.

Looked where at the what?

"We did a preliminary look at the PFD of a few of these SIF's and we think there is something we can do in the BPCS."

PFD is another acronym, and it means Probability to Fail on Demand. The probability to fail on demand (PFD) can be calculated using the dangerous failure rate (λD) and the testing interval (TI). The mathematical relationship, assuming that systematic failures are minimized through design practice, is as follows:  PFD = λD * TI/2.  The equation shows that the relationship between PFD and TI is linear, thus longer times between tests results in larger PFD values.

PFD means that when a demand (in this case an unsafe condition) occurs, there is a possibility that an undetected failure in some element of the safety loop (SIF) will prevent the SIS from performing the necessary shut-down action.

In terms of automobiles, PFD is the likelihood that the air-bag will not deploy in an accident.
Adding PFDavg to the SIL table.

BPCS is defined in safety standards as, "system which responds to input signals from the process, its associated equipment, other programmable systems and/or an operator and generates output signals causing the process and its associated equipment to operate in the desired manner, but which does not perform any safety instrumented functions with a claimed SIL ≥1.”

The short definition is that the BPCS is what for decades has been called the process control system. The BPCS can be a single-loop, panel-based instrument, a distributed control system (DCS) or a programmable logic controller (PLC) with some type of operator interface.

What Gomer is telling Mr. B. is that he and his buddies took a cursory look at the probability that at the same time a demand occurred (unsafe condition existed) that one of the devices (sensor, logic solver, etc.) that made up the few safety loops (SIF) would actually fail (on demand) and prevent the automated shut-down logic from being executed. Gomer was also suggesting that there was a possible solution to preemptively detect these sorts of failures using the basic process control system (BPCS) – though his explanation was way too simplified.

What Gomer had in mind was to access the HART diagnostic information that often goes unmonitored in safety system devices. Since the Springfield Snacks and Pesticides plant already was using HART multiplexers to access the diagnostic information inside most of the process system transmitters, Gomer's thinking was that by adding another HART multiplexer just for safety system devices, they would be able to detect device failures before a demand thereby improving the SIS's reliability.

While I applaud Gomer's forward thinking use of HART diagnostics to improve SIS reliability, that solution may not be appropriate for every company.

Reaping the benefits of HART diagnostics requires that the organization embrace a proactive maintenance culture accompanied by an investment in HART diagnostic utilization training.

When installed properly, HART multiplexers can extract diagnostic information from safety system devices without influencing the reliability of the SIS.

We'll talk a bit more about the relationship between the BPCS and the SIS later. In the meantime, keep in mind that 21st-century operator interface terminals provide a window to a variety of systems and applications, including the BPCS, HART multiplexers, safety system logic solvers, data historians, online modeling and optimization applications, etc. The days of "different tubes for different views" is long gone.

Unsafe production

"Also Mr. Barns, ever since corporate insisted on extending the time between scheduled shutdowns, it has been playing havoc with our full- and partial-stroke testing periods.”

Full-stroke testing is the term used to define when each SIF (safety loop) is fully tested, meaning each discrete sensor is forced to its action state; each analog transmitter is forced to its action value; the logic solver is permitted to execute its programmed logic; and final elements are permitted to change to whatever state they've been instructed (i.e., on/off valves fully open or close).

Because full-stroke testing is a complete test of the automated shut-down system, it is usually only conducted when the process is shut down for scheduled maintenance (i.e., scheduled turnaround).

Note: Remain aware that testing the SIS when the process is shut-down means final elements are not working against "true" process conditions (i.e., flow, pressure). The most serious risk is that a valve might have undetected leak through.

Partial-stroke testing is almost always a test of final elements (i.e., on/off valves). Partial-stroke testing is the term used to define how parts of an SIF (safety loop) are tested without actually permitting devices to go all the way open/close. When properly performed, partial-stroke testing should never interrupt production. Note: Partial stroke testing is conducted under actual process conditions.

Note: Clamping mechanical travel stops to the valves shaft permits manual partial-stroke testing, but often eliminates other final device elements from the test. You may only take credit for the SIS elements you actually test.

During the design of a safety instrumented system (SIS), several assumptions are used in calculations, including establishing the safety integrity level (SIL) value assigned to each safety loop (SIF). One of those assumptions is the amount of time that will elapse between when each safety loop (SIF) can be full-stroke tested. The longer the time between each full-stroke test, the greater the PFD thus the greater the SIL value that is required for that safety loop. Note: PFD (probability to fail on demand), MTTD (mean-time-to-detect, and MTTR (mean-time-to-repair) are some of the assumed values used in determining an SIS's design requirements.

If full- and partial-stroke testing has been accounted for from the very beginning, then the period between tests has also been included in establishing the SIL value for each safety loop (SIF). When the production times are extended without considering the impact on full- and partial-stroke testing, the process is very likely operating in a degraded, less capable state.

Partial-stroke testing is recognized within safety standards as a permissible way of extending the period between full-stroke testing; but the standards also caution that you can't use partial-stroke testing as a substitute for full-stroke testing. (See graphic, "Usefulness of Partial-Stroke Testing.")

What Gomer is telling Mr. B. is that because of the corporate mandated to extend plant operating schedules by default, that mandate also extended the testing periods of the time between full-stroke testing of safety loops and that is a problem.

Note: There are a number of process plants worldwide that are running much longer between planned shut-downs than they did just a decade ago. Unless those plant owner/operators have reviewed, recalculated and possibly redesigned (upgraded) each of their safety loops to accommodate the longer times between full-stroke testing, there is a very good possibility that they are not in compliance with industry safety standards, at least part of the time.

Yea, right!

"Mr. B., I know I don't have to tell you how OSHA feels about IEC 61511 and IEC 61508.”

Like many of us, Mr. Barns probably didn't have a clue about OSHA's take on IEC 61511 and IEC 61508, and so he likely nodded his head knowingly.

Well sometimes that's okay, but when most people hear the term OSHA (U.S. Occupational Health and Safety Agency), or some similar regulatory agency, they immediately go into "pay attention" mode.

The two IEC documents have been internationally recognized as consensus standards written specifically for electrical/electronic/programmable electronic safety-related systems. That means that these standards represent "good engineering practice."

IEC 61508 came first, and it is quite detailed. It was developed to cover a variety of industries. IEC 61511 is a process-industry interpretation of IEC 61508, thus in many places, IEC 61511 references back to IEC 61508.

For the purists among us, IEC 61511 began life as ISA S84. S84 was harmonized with IEC 61511 in 2000. At the time of harmonization, S84 retained a "grandfather" clause. The concept of the "grandfather clause" in ISA-84.01-2004-1 originated with OSHA 1910.119.
The grandfather clause's intent is to recognize prior good engineering practices (e.g., ANSI/ISA-84.01-1996) and to allow their continued use with regard to existing SIS. The grandfather clause (ISA-84.01-2004-1 Clause 1.0 y) states: "For existing SIS designed and constructed in accordance with codes, standard, or practices prior to the issuance of this standard (e.g., ASI/ISA-84.01-1996), the owner/operator shall determine that the equipment is designed, maintained, inspected, tested and operated in a safe manner."
The grandfather clause establishes that the owner/operator of an SIS designed and constructed prior to the issuance of the standard should demonstrate that the "equipment is designed, maintained, inspected, tested and operating in a safe manner." There are two essential steps:
  1. Confirm that a hazard and risk analysis has been done to determine qualitatively or quantitatively the level of risk reduction needed for each SIF in the SIS.
  2. Confirm that an assessment of the existing SIF has been performed to determine that it delivers the needed level of risk reduction.
    You are allowed to leave the system as is if you can determine that the systems are operating safely. Some users cling to the notion that the comparison is against the practices at the time the plant was built?something akin to building codes. Their thinking is that if they don't change anything they are fine. That's incorrect thinking.
The ALARP (as low as reasonable practicable) concept requires that the risk be driven lower when the costs are practical. New practices sometimes include practical things, such as very affordable SIS solutions. The civil court and regulatory systems also seem to want them. So, there are cost and moral arguments for moving forward with partial upgrades as they become practical and feasible.
Technically, the S84 committee documented in TR84.00.04 that the determination had to be at least based on a risk assessment of the current design and management system to determine the risk reduction required and verify that the installed systems are capable of achieving it.
Practically, the equipment performance is estimated for the purposes of the design calculation. Then the performance is monitored in the field and when the performance does not match expectations, the assumptions have been invalidated and the risk gap must be addressed. This involves root cause analysis to understand whether the frequency of failure can be reduced. In some cases, this will result in the replacement of the existing equipment with better-performing models.
Ultimately, each SIS solution is likely to organically evolve as problems are found or when better technology becomes available that has advantages that outweigh its costs.
The key principles of both IEC standards are the:
  • safety life cycle
  • safety integrity levels (SIL).
The safety life cycle is just what you imagine; a continuous review and improvement cycle that has been designed to specifically address the safety system from its initial design to its eventual retirement.
We've already discussed SIL (safety integrity level) so we won't rehash it here.
To understand Gomer's comment "…how OSHA feels about IEC…" we need to look at two items.
The first is the U.S. National Technology Transfer and Advancement Act of 1995. This act requires that all federal agencies (i.e., EPA, FDA, OSHA, etc.) recognize existing consensus standards, such as IEC 61511 and IEC 61508. That means that all government agencies have been instructed to accept the premise of consensus standards and abide by the standards' requirements.
Second, in 2000, OSHA sent a letter to ISA. In that letter OSHA acknowledged that S84 (now IEC 61511) had been officially recognized and generally accepted as good engineering practices for SIS.
Additionally, though OSHA's 1910.119 (PSM – Process Safety Management) regulation does not include specific information on the requirements for safety systems, it does require that facilities perform a process hazard analysis (PHA) and take measures to mitigate identified risks. OSHA's mention of safety systems is simply, "The employer shall document that equipment complies with recognized and generally accepted good engineering practices." When we consider that simple statement alongside the 1995 Technology Transfer and Advancement Act, we can only conclude that IEC 61508 and IEC 61511 or something very similar, must be followed.
What Gomer was subtly reminding Mr. Barns was that if the plant had an incident that resulted in an OSHA investigation, the investigators would quickly realize that the plant was not conforming to IEC safety standards, and fines would most certainly be levied and someone might even end up going to jail.
"What would really be helpful is if we replaced our old SIS with one from the same vendor as our BPCS; that way everything would be 'smart'."
"Ah" thinks Mr. Barns, "all of this gibberish was just a guise to get me to buy some new toys for the boys."
We've already discussed SIS and BPCS, so let's take a quick peek at what Gomer meant by "smart."
Each new automobile year brings us ever more technologically advanced vehicles. As you touch the door latch of one of today's luxury vehicles, it recognizes who you are and begins adjusting the seat, mirrors and sound system to your preferences. When you put the key in the ignition and turn it to start, or in some cases simply push the "smart" start button, you witness a series of automated checks and diagnostics being performed. Anti-lock brakes – OK; fluid levels – OK; front air bags – OK; side air bags – OK; light bulbs – OK; navigation system – OK; tire pressure – OK, …you get the idea.
All of this and more is the result of digital technologies and a high-speed digital communication network that is enabling advanced levels of diagnostics designed to make 21st-century automobiles more reliable and safer.
Not surprising, process control and related safety instrumented systems are also taking advantage of similar digital technologies. No longer do analog transmitters (i.e., pressure, temperature, level) provide only a measured value. T they are also capable of running diagnostics to determine if the process sensing lines are plugged, or if the actual sensor is drifting out of range. Final elements (i.e., pumps, motors, valves, etc.) can also be loaded with digital technology. For example, onboard motor diagnostics can detect failing bearings and higher than normal temperatures. Also, valve diagnostics can tell if the valve is sticking or is not fully closing when it should. Inside microprocessor-based controllers and logic solvers, a host of checks for memory errors, unauthorized changes, and changes that might prove harmful given the current process state are constantly taking place. Our digital communication networks are constantly verifying the presences of other devices and the validity of data sent and received. In short, the list of available diagnostics in 21s -century control and safety systems made available by digital technologies is quite impressive and growing every year.
So when Gomer said, "…that way everything would be ‘smart,'" he was talking about taking advantage of all the advanced diagnostics that have become a part of every 21st -century digital control and safety system on the market. Yes, there are differences among manufacturers, but thanks to open standards the differences are not that great.
It comes down to this: Why wouldn't you want your plant to be at least as capable of self-diagnosing as the car you drive?
Note: There are ongoing arguments about the pros and cons of integrating the SIS and BPCS. Here's the simple truth. The IEC safety standards insist that the ability of the SIS to perform its actions on demand never be compromised. That makes perfect sense. However, the safety standards do permit the SIS to share what it is doing with "outsiders." I like to refer to that sort of sharing as "observational integration," meaning that the SIS information is displayed on the same operator interface used to interact with the BPCS, however, the operators are not permitted to change anything in the SIS. It's somewhat akin to watching the instrument panel of your Chevrolet Impala as it goes through its pre-start checks. You are made aware of what's going on, but you can't change things. That same form of "observational integration" is permitted with the SIS.
When evaluating integrated BPCS/SIS solutions, here are the major features to look for:
Secure Separated Databases - Separate databases securely store the safety and control strategies and make use of separate and unique software modules using dedicated tools. Maintaining separate tools with separate databases prevents unauthorized changes or corruptions, decreases safety risks and reduces the possibility of common cause failures.
Database Integrity and Security – Pre-configured modules that are protected from viruses and harmful hacking by built-in protection mechanisms that check the integrity of the software before installation, after installation and during run time. Seek solutions that ensure the integrity of all data accessed through the SIS engineering workstation and the integrity of the application software residing in the SIS logic solver is protected against unauthorized changes during the entire SIS life cycle.
Managed and Protected Database Environment - Seek a secure, multi-level login scheme that protects the SIS solution from inadvertent and unauthorized changes. Such a login scheme will use a dedicated protection mechanism with several access levels for the engineering application, loading of the application in the controller and forcing points in the SIS logic solver. It will also include an automated user password expiration and automated logoff after a pre-defined period of inactivity, thus protecting applications from accidental or unauthorized changes.
Dedicated Software and Hardware - Seek solutions that use dedicated SIS hardware and software that has been intentionally designed and third-party- certified according to IEC61508 safety standards. Additionally, verifying that the BPCS and SIS hardware and software are separate and diverse minimizes the risk of common mode failures. During implementation, ensure that safety and process control strategies are developed and tested by different groups using dedicated methods.
"Of course that means we really need to install exida- or TÜV-certified sensors and final elements."
Each time we hear that something needs to be certified, we also see dollars going out the door. That can be true for SIS devices.
When Gomer referenced exida and TÜV, he was talking about two, independent third-party certification organizations.
When it comes to specifying SIS devices, the IEC safety standards give you two options:
  • Self-prove each device
  • Purchase certified devices (purchased certified).
An owner/operators decision to self-prove SIS devices requires a robust self-certification process that captures and documents the information and performance of the various devices that are being self-proven. The information about devices that the self-certification process must document includes:
  • a clear description of each device's design revision information;
  • reliability data for identical or very similar applications, including applicable conditions and/or restrictions for use of each device;
  • results of operating software compliance as defined in IEC 61508-3;
  • procedures in place to verify that each device meets functional requirements, is qualified (rated) for use in the expected environment, and the materials of construction are suitable for expected process conditions, including actual test results from use in similar, but non-safety critical applications;
  •  acknowledged competency to review the design aspects of both mechanical and/or electrical components, including component failure modes, fail-safe vs. fail-danger, any claimed automatic diagnostics and internal redundancy in order to produce a quantitative failure rate. (This number will eventually be used in calculations that determine if a particular design meets its defined SIL requirements);
  • acknowledged competency that is capable of combining sophisticated design analysis processes, tools and testing methods with a thorough review of both the devices original design and all subsequent modifications to the electrical, mechanical and software aspects of each device with the intent of uncovering design errors;
  • regularly conducted audits of each device's manufacturers change- management processes for each device being used or being considered for use in an overfill protection system; and
  • a documented "safety case" describing, in significant detail, how each manufacturer's device meet each requirement of IEC 61508.
Because a self-certification program must capture actual operating experience, IEC 61508 does provide minimum operating experience guideline hours.
While meeting the above requirements is onerous, that is not all that you must do. You must also be able to show that you were able to detect and record each and every dangerous failure that occurred during these time periods. In short, your self-certification process must be almost 100% effective at capturing device failures.
Your engineers may argue that your company has really great operating experience with this or that device. That may be true, but you need to ask them two questions:
1) Can they show you the documentation about this or that "self-proven" device;
2) Who verified that the "self-certification" process used to produce that documentation meets IEC requirements?
The importance of asking those two questions and being comfortable with the answers is summed up by asking yourself; "If we get it wrong, who is most likely to go to jail?"
The alternative to establishing a self-certification process is to utilize certified devices from any one of the growing number of manufacturers offering devices certified for SIS applications.
When you look closely at how manufacturers are certifying devices for SIS applications you find three different approaches:
• Self-developed device certification processes;
• Self-developed and third-party audited device certification processes;
• Independent third-party device certification.
The first is self-explanatory. The manufacturer develops the certification process per its interpretation of IEC standards and certifies that its devices are tested and proven against those processes.
The second is similar to the first with the caveat of having an independent third-party review that the manufacturer developed procedures are consistent with IEC standards.
Manufacturers choosing the third approach submit their devices to an independent third-party (i.e., exida and/or TÜV) who then uses its own certification processes to test and certify that the device meets the manufacturer's safety system claims.
Regardless of which of the three "purchased certified" approach is used, when you purchase a certified device, it should come with a copy of the device certification and a detailed user safety manual that includes such things as restrictions on where and/or how the device may be used.
You may view a comprehensive list of third-party certified devices at
Yep, regardless of how you go about it, certification equates to dollars, but in the case of conforming to IEC safety standards, you can either spend dollars to establish your own self-certification process, or you can pay the slightly higher per device cost and purchase third-party certified SIS devices. Doing neither and having a major incident will undoubtedly cost even more.
With that I would like to leave you with this thought; the most likely cause of a shut-down that was initiated by the Safety Instrumented System (SIS) is most likely the result of one of three things:
1. A sensor (input) provided a false signal to the logic solver;
2. Some form of human error occurred;
3. There was an unsafe process condition, and the SIS did exactly what it was designed to do.
If you are told the cause of the shut-down was because of a false signal (#1), you need to review the maintenance and testing procedures of the sensor, logic solver and final element for that SIF (safety loop). It shouldn't take too long to review that one SIF, and the findings will likely reveal that your procedures are inadequate or more likely, aren't being followed. Either way the time spent to find and correct the cause of that unscheduled shut-down will pay huge dividends in the future.
If the cause of the shut-down was the result of human error (#2), you need to review training and operational procedures. One common cause is the result of technicians performing scheduled, routine testing of the SIS while the process remains operational. For example, manually conducted partial-stroke testing is a fairly complex procedure requiring the proper application of mechanical travel stops. Sometimes the travel stops are improperly installed. The result is an unscheduled shutdown.
If the cause of the shut-down was because an unsafe condition was detected (#3), you need to review what was going on with the process and the BPCS and perhaps more important, you need to review why your operators didn't notice and take appropriate action before the process reached an unsafe condition.
Regardless of the findings, every unscheduled shut-down should be viewed as an opportunity to improve production performance.
The Internet is awash with SIS related information. Here's a few that I believe represent the best-of-the-best:
Emerson's PlantWeb University SIS Course – 11 different courses. Each will take about 15 minutes to complete and you can earn points for some fun gifts.
Emerson's DeltaV Book Store includes process control-related books from a lot of different authors and sources. It's really a good single-stop shop.
SIS-TECH Technical Information – SIS-TECH is an independent company that specializes in SIS consulting, services and training. The SIS-TECH web site has a really good collection of SIS related material, and it's all free.
Exida is an independent company that specializes in SIS consulting, training, competency certification of individuals and third-party device certification. exida also hosts a regularly updated SIS device certification list.
TÜV Rheinland Group is an independent company that specializes in SIS related services including competency certification of individuals, and third-party device certification.