Relief Systems – Understanding Design and Design Basis

In compliance audits all over the country, we’re finding that the requirements for documenting the relief systems are not being met in many PSM programs. How bad is the situation? About 1/3rd of the relief documentation we see shows that the relief system DOES NOT meet the chosen design basis. About 90% of the remaining relief documentation doesn’t address the chosen design basis enough to make a case either way.

First, let’s take a minute to make sure we understand the difference between design and design basis.

Design Basis: The design code, standard, or RAGAGEP chosen to serve as the requirements. You can think of it as the conditions for success.

Design: How the facility actually met the Design Basis. This should include the “work” behind the design – the measurements, calculations, etc.

Let’s say we chose IIAR2-2008b as our Design Basis. Your documentation is likely limited to some spreadsheets provided by an engineer that shows the measurements and calculations that the engineer did to show that the piping design met the RAGAGEP.

That’s great. We definitely need that and that’s why you hired an engineer in the first place. But there is more to meeting the design basis than doing advanced math! You need to include an explanation of how all the other requirements were met. To give you an idea, of the sorts of things that you would need in your documentation for just IIAR-2 2008:

  • (11.1.1) The relief system meets ANSI/ASHRAE 15-2007 Section 9.4 [ref.4.1.4] excepting section 9.4.3
  • (11.1.2) If stop valves exist downstream of a relief device, that they are locked open when in service. Reference to a car-seal program to control the valve position.
  • (11.1.2) If stop valves exist downstream of a relief device, the relief calculation includes the pressure drop across the stop valve. Reference to the engineering calculations to back this up.
  • (11.1.3) Relief valves are installed as near to equipment being protected as possible.
  • (11.1.4) Unless hydrostatic the relief is connected at the highest practical point.
  • (11.1.5) If installed in refrigerated spaces, precautions have been taken to prevent moisture buildup in the valve or relief line. Reference maintenance procedures or PHA section as necessary.
  • ( The relief valves are set to function at a pressure equal or lower than the design pressure of the protected system.
  • ( If installed, rupture discs are set to function at a pressure equal or lower than the design pressure of the protected system.
  • ( If installed, rupture discs conform to Section VIII, Division 1, ASME Boiler and Pressure Vessel Code.
  • ( If installed, rupture discs ahead of relief valves are at least as large as the relief valve inlet.
  • ( If installed, rupture discs have provisions in place to detect pressure buildup between the disc and a relief valve. Reference to the maintenance procedure (such as daily walk-through) and any automated systems in place.
  • ( Pressure relief valves settings are set by the manufacturer.
  • ( Pressure relief valves are marked to conform with Section VIII, Division 1, ASME Boiler and Pressure Vessel Code.
  • ( Rupture discs are marked to conform with Section VIII, Division 1, ASME Boiler and Pressure Vessel Code.
  • ( & 11.1.8) The capacity of the relief devices are stamped on the valve or available.
  • (11.2.1) Pressure vessels relief protection complies with Section VIII, Division 1, ASME Boiler and Pressure Vessel Code
  • (11.2.2) If a pressure vessel is capable of being isolated by stop valves, it must have overpressure protection.
  • (11.2.3) Reliefs are sized in accordance with IIAR2-2008b 11.2.7. Reference to the engineering calculations to back this up.
  • (11.2.5) Vessels with internal volume of 10 cubic feet or greater are equipped with three-way valves and dual pressure relief valves or a single valve if the vessel is on the low-side, can be pumped out and the other vessels are protected in accordance with IIAR2-2008b 11.2.7.
  • (11.2.6) When pressure is relieved into other vessels, that the back pressure is taken into account and that the affected vessel has its reliefs sized for the combined capacity of both vessels. Reference to the engineering calculations to back this up.
  • (11.2.7) The discharge capacity of the relief device meets the requirements of this section. Reference to the engineering calculations to back this up.
  • (11.2.7) When one relief device serves multiple vessels, the discharge capacity of the relief device meets the requirements of this section. Reference to the engineering calculations to back this up.
  • (11.2.7) When combustible materials are used with 20ft of a pressure vessel, the modified formula is used. Reference to the engineering calculations to back this up.
  • (11.2.8) The rated discharge capacity of the relief valve was determined in accordance with Section VIII, Division 1, ASME Boiler and Pressure Vessel Code. Reference to the engineering calculations to back this up.
  • (11.2.8) The capacity marked on the nameplate of the relief device is expressed in lb/min air or in standard ft3/min (SCFM) of air at 60°F
  • (11.2.9) The rated discharge capacity of rupture discs is calculated with the equation in this section. Reference to the engineering calculations or manufacturers documentation to back this up.
  • (11.2.9) Provisions to prevent plugging the piping when the rupture disc relieves are present.
  • (11.3.1) No stop valves are present on the inlet or outlet piping of the reliefs with procedures in place conforming to ASME Boiler and Pressure Vessel Code Section VIII Appendix M. Reference to the procedures if applicable.
  • (11.3.1) The size of the inlet piping to a pressure relief device is not less than the inlet size of the pressure relief device.
  • (11.3.3) Relief piping conforms to IIAR2-2008b 11.3.3,,,, and
  • (11.3.4) The size of the relief pipe is not less than the outlet size of the relief device.
  • (11.3.4) For headers, relief piping is sized to accommodate all the relief devices that are expected to discharge simultaneously at the lowest pressure setting with consideration given to pressure drop in all downstream piping. Reference to the engineering calculations to back this up.
  • (11.3.5) Where piping or components may contain liquid that could be isolated during operation or service, IIAR2-2008b 11.4 for hydrostatic protection is also applied.
  • (11.3.6) All atmospheric reliefs relieve to the outdoors.
  • ( The maximum length of the discharge piping is determined by the method in IIAR2-2008b, Appendix A. Reference to the engineering calculations to back this up.
  • ( Atmospheric relief piping has provisions for draining moisture. Reference to maintenance procedures.
  • ( The relief point of a relief device to the atmosphere is 20’ or more from any window, ventilation intake, or personnel exit.
  • ( The direction of discharge is vertically upwards.
  • ( The discharge from pressure relief devices is 15’ or higher above the adjacent grade or roof level and arranged to avoid spraying of refrigerant on persons in the vicinity. Reference to PHA as necessary to deal with catwalks and platforms.
  • (11.4) This section is applied when equipment or piping sections are isolated manually or automatically.
  • (11.4.1) Only trained technicians taking all necessary precautions to prevent overpressure due to hydrostatic expansion will manually isolate equipment. Reference to training, LO/TO program, written SOPs, etc.
  • (11.4.3) Equipment or piping that can be isolated automatically is protected by a hydrostatic relief device.
  • (11.4.3) Hydrostatic relief devices are not used as shut-off valves.
  • (Appendix A) Relief design is calculated to conform to this section.
  • (Appendix E) Relief design for positive displacement compressors is calculated to conform to this section.

We like to cover all these things in a single narrative with appendices for engineering work. You can do this any way you like as long as you address the requirements of your chosen RAGAGEP. One method is to use GCAP’s IIAR2-2008b RAGAGEP Audit Checklist provided for all GCAP PSM students.

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What’s the deal with Valve torque?

A common question I get is whether or not flanged and bonneted valves need to be torqued when they are installed. Unfortunately, many of these questions are due to OSHA citations – Ideally you want to answer this question BEFORE the OSHA inspection.

The short answer is: Yes, you need to torque valves and bonnets to the manufacturer’s recommendations when you install them.

 The long answer begins with a little history…

The 2005 version of IIAR-3 (Valves) section 5.8, states: “The applicable tightening torque values for the valve bonnet, flanges and other pressure-containing attachments to the valve shall be specified by the manufacturer and made available on request.”

Valve manufacturers went ahead and complied with this and every major valve manufacturer that we’re aware of published torque recommendations. The IIAR revised their wording in 2012 to “The applicable assembly and installation procedures for the valve bonnet, flanges and other pressure-containing attachments to the valve shall be specified by the manufacturer and made available on request.” However, the valve manufacturers had ALREADY posted the torque recommendations.

For one example, R/S Parker, see page 216-218 of the link below:

R/S Parker Valve Catalog

That link would be the “applicable assembly and installation procedures,” right? Even the current version of IIAR-2 states that: “10.5.1 Valves (or flange sets) with specialized tightening requirements shall be installed according to manufacturer’s instructions.”

PSM also requires us to adhere to manufacturer’s instructions:

1910.119(j)(6)(ii) ​ ​Appropriate checks and inspections shall be performed to assure that equipment is installed properly and consistent with design specifications and the manufacturer’s instructions.

In my opinion, and based on citation history, the belief that valve torque is NOT required is unsupportable. If the valve manufacturers removed all their torque requirements from published documents, then it’s possible the issue could be avoided. But honestly, that’s exactly what they are trying to do – Avoid the conversation. It’s really infuriating that the same people that wouldn’t think of installing a new head on their hot-rod without a torque wrench are the people that usually give you the most grief about valve torque.

The real question is: Is the flange or bonnet torque important? The answer to that is undeniably: Yes.

Over-torqueing pinches gaskets making leaks more likely and extreme over-torqueing on bonnets can warp them to the degree that it impairs the function of the valve or regulator.

We should torque the flanged valves and bonnets to manufacturer’s specification not because PSM tells us to, or because the IIAR tells us to, or even because the manufacturer tells us to. We should the flanged valves and bonnets to manufacturer’s specification because it is the right thing to do.

p.s. Previous discussion and citation at this link:

p.p.s. You can’t torque old bolts reliably. Once you’ve torqued the bolt, you don’t go back and torque it again since the act of tightening a bolt actually stretches it minutely. Lubrication on bolts drastically changes the actual bolt tension for a given torque – you shouldn’t lubricate bolts that you are going to torque unless the torque specification specifically tells you to. Unless stated otherwise, torque specifications are assumed to be dry, clean and new threads.

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EPA RMP Executive Summary

As part of GCAP’s PSM course, we pull the publically available RMP from for each facility in the class. We’ve seem some strange things in the Executive Summary and wanted to share some guidance on what exactly should and should not be there.

First, let’s look at the most common mistakes:

1) Misunderstandings of Executive Summary: The Executive Summary is meant to be a quick synopsis of the RMP filing, not a brief summary of the executives at the facility. Seriously, a facility had actually put mini-resumes of the executives at the facility in their executive summary.

2) Long, rambling consultant boilerplate: The Executive Summary is supposed to be brief and include only the required information.  Reading some of the Executive Summary’s, you would think that the consultants were paid by the word.

3) The OCA or Offsite Consequence Analysis: While this information was originally required, the law was changed in 2004 to remove this requirement due to National Security concerns. As explained by the EPA:

“A summary of the off-site consequence analysis (OCA) for the worst-case and alternative release scenarios(s) is no longer required to be included in the Executive Summary. While the RMP rule originally required that the Executive Summary briefly describe the OCA for worst-case and alternative release scenario(s), EPA amended the RMP rule in 2004 to remove this requirement because of security concerns. Your Executive Summary should not describe nor include information concerning your worst case or alternative release scenarios.” —-EPA 555-B-09-001

4) Misunderstandings of “Planned changes to improve safety”: Occasionally, you will see someone like EVERY PHA, II, CA and MI recommendation in the system and the status of that recommendation.  The EPA says they expect you to list the following:

“..any upcoming events such as training, installation of new mitigation or control equipment or technology, organizational changes, etc., that will improve safety at your facility. —EPA 555-B-09-001

Usually you can simply provide a statement such as “Through our ongoing implementation of the PSM/RMP program, ABC Company looks continuously for possible ammonia refrigeration system changes to improve safety in our facility.

What should the Executive Summary include? First, let’s look at the purpose of the executive summary:

“The Executive Summary must include a brief description of your facility’s risk management program. You determine the length; it may be as short as two or three pages or, if you have many processes, it may need to be longer. You should view the Executive Summary as an opportunity to communicate in your own words the nature of the risks posed by your facility to your community and to explain what you have done to minimize those risks. The summary can be an excellent vehicle to display the effort and resources your facility has put into its accident prevention program. —EPA 555-B-09-001

Here is the information actually required in the Executive Summary:

  1. The accidental release prevention and emergency response policies at your facility. Describe your facility’s overall approach to chemical safety. You may want to include any corporate policies (if applicable) and an overview of senior management commitment to safety and implementation of safe procedures.
  2. Your facility and the regulated substances handled. Provide a description of your facility so that the public has a clear picture of the facility, its processes, and products. Describe the primary activities at the facility (e.g., manufacturer of polyethylene, pulp mill, etc.) and the regulated substances used.
  3. The general accidental release prevention program and chemical-specific prevention steps. You may wish to mention the rules and regulations with which your facility complies, such as the OSHA PSM rule. You should also highlight practices that you believe are important to your prevention program. The steps you list may be either technological (e.g., backup systems) or procedural/managerial (e.g., improved maintenance or training).
  4. The five-year accident history. This should be a written summary; for example, “We have had five accidental releases of chlorine in the past five years; the largest release was 1,500 pounds. No one offsite was injured, but several houses were evacuated as a precautionary measure during the October 2005 and May 2006 releases.”
  5. The emergency response program. Briefly describe the elements of your response program. These may include coordination with local emergency responders, training received by personnel, drills conducted by your facility, public notification and alert systems, as appropriate
  6. Planned changes to improve safety. List any upcoming events, such as training, installation of new mitigation or control equipment or technology, organizational changes, etc., that will improve safety at your facility.

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Lessons Shared #2 – “That policy is for other people…”

This post is part of a series on Lessons Shared

This incident is about a common problem in PSM plants: Some people don’t think the rules apply to them.

This story is from a friend who works as a refrigeration contractor. Many smaller facilities lack their own qualified and experience maintenance staff and they hire contractors to do basic maintenance on their systems such as changing oil filters and equipment inspections. My friend had a contract with a company to stop by twice a week and walk through their mechanical room; taking readings and doing basic preventative maintenance.

One day, after he was finished with his work in the mechanical room, he walked out into a hallway and saw a young man on a ladder with a sawzall. The young man was in the process of cutting into a 2” Ammonia High Pressure Liquid line. My contractor friend quickly stopped him – thankfully before he managed to cut through the pipe wall. The young man had no idea what was in the pipe and was not aware how close he came to dying.

How did this situation happen?

It turns out that the Plant Manager had hired the young man (a golfing buddy’s son who was home on break from college) to do some little projects around the plant. The Maintenance Manager had been bugging him about his backlog of work so the Plant Manager took it upon himself to get rid of some of the projects, including a project that involved removing some abandoned water piping. He had told one of the maintenance workers to “tag the pipes you want removed with some fluorescent orange spray paint,” and that’s exactly what happened.

The only work instruction given to the young man was “Go cut out all the old piping. It’s been marked orange so it’s easy to see.” It shouldn’t be surprising that the young man saw the orange High Pressure Liquid Ammonia piping and thought that this was some of the piping to be removed. There was no safety briefing concerning the hazards in the area. There was no training on the location of safety showers, plant alarms or evacuation routes. There was no contractor paperwork.

Why? The plant manager didn’t go through the usual procedure because he thought this was just a little project that would only take a few days. He also explained that the young man wasn’t supposed to be working on the Ammonia system so he didn’t think that PSM applied to him. After all, he reasoned, this is just a college kid making a couple bucks while on break! He also said that he was the Plant Manager – and “those rules were put there to control hourly people, not management!”

It’s not uncommon to find these situations where management thinks that they are above the system and not part of it. It usually happens in elements such as Training, Operating Procedures, Contractors and Management of Change. On the other hand, there are a lot of experienced operators who think the same thing about SOPs: “They are there for the new guy, not for me!”

PSM policies and procedures are put there for EVERYONE who could affect, or be affected by, the process. While it’s possible to have different rules for different people, these different rules must be analyzed in the Process Hazard Analysis.

Please use this story to talk to your maintenance staff about the VERY REAL hazards of acting outside of the PSM program. Hopefully this story hits home and if they find themselves in similar situations, they may take some time to consider their actions before their well-intentioned efforts inadvertently results in another of these stories.


Note: How should this young man have been handled by the PSM system? The young man should have been viewed as a contractor under their PSM guidelines which should have required, at a minimum:

    • An evaluation of the hazards presented by the contractors work. This should have included fairly obvious questions such as “What if he misidentifies the piping?” This should have led to a clear marking scheme that would not have been confused with existing piping that wasn’t being decommissioned.
    • Training on the hazards present in, and around, the process.
    • Training on the alarm and evacuation procedures.
    • An evaluation of the contractor’s safety training. (Since he wouldn’t have had his own safety programs, his understanding of the facility’s programs would be evaluated)
    • An evaluation of the contractor’s adherence to safety programs.
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Respecting Maintenance and Operational Skill

I recently read a fascinating article from Japan concerning a new “trend” at Toyota where they are reintroducing manual processes along-side their automated robotic processes. Essentially, they are putting smiths into their factories where workers are taught how to fashion something like a crankshaft by hand.

They are still making nearly all their parts by robots, and they always will. The point of these manual processes is so that employees can better understand what the robots are doing. What they have found is that their process improvement efforts were stalling without this process knowledge. Once they started building the hands-on knowledge, they experienced fantastic results:

Learning how to make car parts from scratch gives younger workers insights they otherwise wouldn’t get from picking parts from bins and conveyor belts, or pressing buttons on machines. At about 100 manual-intensive workspaces introduced over the last three years across Toyota’s factories in Japan, these lessons can then be applied to reprogram machines to cut down on waste and improve processes…

…workers twist, turn and hammer metal into crankshafts instead of using the typically automated process. Experiences there have led to innovations in reducing levels of scrap and shortening the production line 96 percent from its length three years ago.

What Toyota is rediscovering here is respect for actual skill. In the vast majority of refrigeration plants I visit, there is a pool of skill in the operating staff that is not being used properly. Worse yet, companies often are unwilling to invest in building skill into their operating staff. A common thought I hear from management is: “What if we train them and they leave?” My response to that is always: “What if you don’t train them and they stay?”

One place where I see this is in Operating Procedures. As a consultant, I am often asked to write Operating Procedures for clients. While it’s certainly possible that a consultant can write a compliant SOP without operator input, it’s extremely unlikely that the resulting SOP will be looked upon kindly by your operating staff. Ideally, you want operator input into the SOP itself so that it truly reflects the way they operate.

In any case, you are losing something when you have a consultant write your SOPs, even if you are getting operator input. What you are losing is the struggle to create them and the skill that the struggle builds. The next time you need a new or modified SOP, you are going to have to call another consultant because you haven’t built the in-house skills necessary to do it yourselves.

In the Toyota article, they discuss one of the practices that they stopped using in a rush to expand. As they explained it, when you were a newly assigned executive, they would give you a project with a three month deadline. Your immediate supervisor knew how to complete the project in three weeks and their bosses knew how to complete it in a matter of days. But at Toyota, they didn’t tell you how to solve the problem. They made you struggle and that struggle built experience in a way that just GIVING you the answers didn’t. They’ve reintroduced this practice because it built SKILL.

We can use this same approach to SOPs: If your people already have the operational skill to understand the process and only lack the skill to write the compliant SOP, you’d be better off investing your efforts in having someone to teach the operators how to write the SOP. Think of it as a training that allows you to “in-source” your SOP building.

I’ve done this all over the country now and in about three days I have always been able to train operators (some of which have very limited computer skills) to use my SOP format templates to write compliant SOPs. Most operators already possess the skills and process knowledge of how the process operates; what they lack is the skill to write the compliant SOP. They WILL struggle, but that’s what I am there to help them with.

Furthermore, the SOPs they build are THEIR SOPs and not some consultant’s. They are significantly more likely to follow the SOPs because THEY were part of their creation and THEY believe them to be accurate.

If you have a budget to get compliant SOPs, please consider training your own staff to create them. You’ll be respecting and utilizing the skill they have while building some new ones. You will not only build the SOPs, you will also build a better maintenance staff.

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Handling Compound Valve and Multi-Valve platforms in P&IDs and SOPs

I was at the IIAR convention a few weeks ago which afforded me the opportunity to do something I’ve long wanted to do: Get a chance to ask representatives from Danfoss, Hansen and R/S Parker to give me their thoughts on properly labeling Compound Valve and Multi-Valve platforms.  I am going to use the Danfoss valves as an example for this article, simply because I have lots of diagrams and pictures around based on past experience with them.

A pair of Danfoss ICF valve stations

The idea of all of these platforms is that you basically get a valve-station in a single valve body. The valves take up less room, require less welding, etc. I don’t have any arguments with any of that: my issue is how I am seeing them referenced on a P&ID and in SOPs.

Let me give you an example:

The valve we are going to talk about is a Danfoss ICF-32-6-3A. It is a fairly common configuration replacing a traditional liquid valve-train.

Schematic of the valve

What I am seeing in the field is that this is represented in the field on the P&IDs as something like this:


In this situation, the entire compound valve is represented by a single tag. This results in SOP steps like this:

1) Close the liquid stop valve on ICF-AU1-01.

That step requires the operator to figure out which of the valves is the liquid stop valve. The correct answer is the first module or M1. We could write the stop to say so explicitly:

1) Close the liquid stop valve (Module 1) on ICF-AU1-01.

However, this step still requires the operator to identify the module. Most of the multi-valves have the Module (or port) number stamped on the valve but paint and insulation could get in the way of that.

What I would prefer to see is a more traditional valve labeling/tagging where each valve module/port is explicitly labeled/tagged. One way to do this while keeping with the same type of P&ID display is as follows:


This would let us change the SOP step to something like this:

1) Close the liquid stop valve on ICF-AU1-01-M1.

Of course, we could always reference each component of the valve with the more traditional names and tags such as :

  • HV-AU1-01 : Hand Valve (Stop in this case) on the air unit.
  • ST-AU1-02 : Strainer on the air unit.
  • LSV-AU1-03 : Liquid Solenoid on the air unit.
  • CKV-AU1-04 : Checkvalve on the air unit.
  • HXV-AU1-05 : Hand Expansion valve on the air unit.
  • HV-AU1-06 : Hand Valve on the air unit.

This might clutter up the drawing a bit, but something like this would be perfectly acceptable as well:


 Whichever method you choose, the performance basis is going to be what your operators understand. When introducing these new types of valves, a little bit of training and employee participation goes a long way!

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$205,000 fine for dumping 40 pounds of ammonia

Kodiak fish processor North Pacific Seafoods pleaded guilty Tuesday in federal court to illegally dumping ammonia into the Kodiak city sewer, while the processor’s chief engineer faces charges of his own.
District Court Judge Ralph Beistline imposed $205,000 in criminal penalties, $55,000 of which should go to the city for “hazardous waste response training” and equipment for sewer and fire department employees, according to an Alaska U.S. Attorney’s Office press release.

Kodiak fish processor North Pacific Seafoods pleaded guilty Tuesday in federal court to illegally dumping ammonia into the Kodiak city sewer, while the processor’s chief engineer faces charges of his own.
District Court Judge Ralph Beistline imposed $205,000 in criminal penalties, $55,000 of which should go to the city for “hazardous waste response training” and equipment for sewer and fire department employees, according to an Alaska U.S. Attorney’s Office press release…

…According to Assistant U.S. Attorney Andrea Steward, the illegal disposal happened in late November 2011. Employees at Alaska Pacific Seafoods “dumped approximately 40 pounds of ammonia waste from its refrigeration system” into the sewer.

–Alaska Dispatch

That’s about $5,000 a pound! The article goes on to say that the chief engineer that directed the dumping is facing a charge for violating their DEC regulated permit.

Please make sure you have a plan in place to deal with Ammonia before you run the risk of finding yourself in this situation!

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Lessons Shared #1 – “The Graveyards are full of Heroes”

I had to fight back tears the first time I read this NIOSH report. Having lived on a family farm for a short period, it was very easy for me to imagine the reaction of the people involved…

A 43-year-old dairy farm owner (victim #1) and his 23-year-old son (victim #2) died from asphyxiation after entering one of two adjacent 8-foot-deep manure-waste pits that were connected by a tunnel. The pits were located under each half of the end of a dairy holding barn and were connected so that both pits could be pumped from one side. The incident was unwitnessed but evidence suggests the following sequence of events. The two victims were pumping the manure from the pit into a manure spreader tank using a pump located outside the barn that was being driven by a tractor’s power take-off. The workers had pumped the manure from the pit containing the pump intake hose; however, the manure from the adjacent pit could not be pumped because the tunnel connecting the pits was obstructed. The father removed a steel grate cover and descended an aluminum ladder into the nearly empty pit. As he began to clear the tunnel of obstruction, the father was overcome. The son entered the pit in an attempt to rescue his father and was also overcome. The victims were discovered 22 hours later by the farm owner’s wife, and the mother of the 23-year-old victim.

There are many lessons we can learn from this incident – even though it isn’t an Ammonia process, let alone a PSM covered process, but the primary one I’d like to talk about is human nature.

It’s human nature to try and help when you see a co-worker in trouble. I think it’s even more common in the blue-collar skilled trades than in many other lines of work: we are “get ‘er done” types of people. We’re used to solving problems on the fly. We’re confident we can work our way out of little jams.

What we have to be wary of is letting our heart over-rule our brain. You’re more likely to add to the body/injury count than you are to help if you don’t stop and think about what you are going to do. Here are some other examples:

  • A 31-year-old male assistant construction supervisor (victim) entered an oxygen-deficient manhole to close a valve and collapsed at the bottom. In a rescue attempt a labor foreman (male, age 34) and the victim’s supervisor (male, age 36) also entered the manhole and also collapsed. All three workers were pronounced dead at the scene by the county coroner. (report)
  • A 25-year-old male electroplater (victim) died after entering a metal plating vat he was cleaning. Four male co-workers also died when they entered the vat in rescue attempts. (report)
  • A 31-year-old male dairy farm laborer entered a manure pit to clear a pipe, lost consciousness, and collapsed at the bottom. In a rescue attempt, his 33-year-old brother, also a farm laborer, entered the pit, lost consciousness, and collapsed. Both workers (hereinafter referred to as initial victim and rescuer victim) were pronounced dead at the scene. (report)
  • A 43-year-old production foreman of a wire processing company was summoned to aid a maintenance crewman (his son), who had collapsed at the bottom of an open top clarifying tank. The 18 year-old summer employee had been overcome by fumes liberated from chemical sludge that he was removing from inside the tank. In a rescue attempt the production foreman collapsed upon entering the tank. He was later removed from the tank. by the fire/rescue team and pronounced dead. The fire/rescue team also removed the crewman. He was admitted to the intensive care unit of a local hospital and later released. (report)
  • Two workers died while attempting to rescue a third worker who had entered a fracturing tank at a natural gas well. A total of four men entered the. tank and were overcome by natural gas. The two workers who died drowned in 30 inches of liquid (water, gas, acid, and possibly oil) which had been released into the tank during “blow down” procedures. The other two workers, both rig hands, required medical treatment at local hospitals. (report)

Please use these stories to talk to your maintenance staff about the VERY REAL hazards of acting “in the moment” in an attempt to rescue their coworkers. Hopefully these stories hit home and if they find themselves in similar situations, they may take some time to consider their actions before their rescue attempt inadvertently results in another of these sad stories.

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The “PSM Lessons Shared” project

Recently, during a PSM class, I had a student with an all-too-common issue: How do I change the incident reporting culture at my facility? As a new PSM coordinator he was struggling because he couldn’t get his operators to report any incidents or near-misses that occurred on the process. We discussed it as a group for a while because changing safety culture is one of the most difficult things you will ever attempt.

It helps if we start with a common definition of culture. “A way of thinking, behaving, or working that exists in a place or organization” is the Merriam Webster dictionary definition that seems to apply best to safety culture. When dealing with culture, it’s good to keep in mind this Tony Robbins quote as well: “It’s not what we do once in a while that shapes our lives, but what we do consistently.”

Your safety culture is the result of the consistent actions and experiences that your company has provided for its employees. This kind of deeply established culture isn’t going to change just by issuing a new corporate policy. It’s likely that your safety culture has built up over years.  Culture has inertia and you shouldn’t expect to counter-act that overnight. If you are to have any chance of changing it, you have to first understand what has caused this culture to form.

In this particular case, it became clear that the culture of not reporting incidents was due to a past practice of criticizing and punishing anyone who reported an incident. It’s a fundamental principle of human nature that we get more of something we reward and less of something we punish. The culture of not reporting incidents can only be changed by changing the perception that negative things will occur if you share your incident with your colleagues and management.

It’s going to take time and careful attention to change such a culture.  For this case, he wanted something low key – something that wouldn’t seem like an overt attempt at changing culture because the employees were instinctively resistant to any type of direct change. How could we begin to change the culture for this student? We decided to attempt to change the culture – not by changing the culture directly – but by changing the perceptions and values of the employees through consistent action on the part of the PSM coordinator. He is going to share incidents from other facilities in the hopes that they start a conversation about similar situations in the plant. If such discussions do occur, he is going to focus the conversations ONLY on the lessons we can learn from the incidents, rather than trying to assess blame or fault.

This is such an interesting idea to me that I decided to help him out. Over the next year, I will provide a monthly post about a single incident relevant to Ammonia PSM so that they can discuss it and learn from it. We’re hoping that just the act of discussing these situations will make the facility more comfortable with the failings of human nature. Hopefully, they will begin to understand the value of incident investigation and the reporting rate will naturally change in response to the changing perception of the value of incident investigation.

If you have any PSM incidents that you would like to share (even anonymously) please email them to me at

Look for the first of these monthly incident posts in the next few days. I look forward to the reports concerning the culture change (if any) over the next year and I will keep you updated as well.

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Should you challenge OSHA citations?

Will Kramer has written an excellent article on why you should challenge OSHA citations.

Based on an analysis of the more than 57,000 citations listed in OSHA’s public inspection databases in 2012, employers achieved an average penalty reduction of 49% by negotiating their citations with OSHA at informal conferences. Of the 33,765 citations of this type, 7% were deleted entirely. This is a victory as the complete elimination of a citation is typically an employer’s primary goal, since that effectively clears the employer’s record in the event of future inspections, which could otherwise result in costly repeat citations.

I’ve had very good luck with informal conferences. Be prepared. Know the law. Know the RAGAGEP.

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