Engineers Week was established in 1951 as a way to promote a diverse and well-educated future engineering workforce by increasing understanding of and interest in engineering and technology careers. Each year, aeSolutions celebrates Engineers Week by hosting fun activities for our employees and by sharing resources and stories that highlight how engineers – and engineering companies – make a difference in our world. This year we asked our employees a series of questions related to engineering and engineering companies as a career choice. We’ll be sharing some of their answers over the course of Engineers Week, which runs from February 18-23. Today’s question focuses on what it’s like to work at an engineering firm. What is your favorite thing about being an engineer or working at an engineering firm? Building things, making things work, solving problems, making society a better place. – Tom M. I think that my favorite thing about working in an engineering firm is the amount of learning that I can accomplish. Whether it's the accounting department, human resources, or the engineers themselves, I am able to learn something new every day. ­– Wyatt S. One of the more satisfying things about this work is seeing a project go from concept to design to implementation.  – Andy G. Problem-solving is my favorite thing.  As a single-parent for 12 years, I honed this skill/gift well. Being a process safety consultant enables me to help industry prevent unplanned incidents that have the potential to harm people, our communities, and environment. – Kelly J. I get to work with high-performing professionals. They are smart and self-motivated. Though they are opinionated I have found them mostly willing to listen to ideas different from their own as long as they are approached in an inclusive way, deliberately looking for common ground. – Ken O. I love working with other highly talented Engineers, the depth of knowledge and technical skills around me is fascinating, there's always something or someone to learn from. – Carolyn B. Engineering is always interesting and is never the same on a day-to-day basis, so I am never bored with my job. Plus, as a consultant, I have worked with so many different clients across a wide variety of industries.  Another positive has been the opportunity to visit many places I might never have otherwise traveled to, such as Guam, Australia, Alaska, Augsburg, Germany, Guadalajara, Mexico, Dublin, and a variety of Canadian cities. – Melissa L. I enjoy solving problems and coming up with solutions that are out-of-the-box. – Kelvin S. I love getting to work with people who are driven and have similar thinking to myself in many ways. I appreciate that engineers at my job are also personable and have good people skills, which is not a given with engineers. – Ethan W. I am able to work on various projects and learn about new technologies. – Mark S. My favorite thing about working at an engineering firm is feeling like my work actually does a difference. – Joel R. How do you describe what you do to your family? I help chemical plant and refinery customers not blow themselves up. – Tom M. My usual line to people that are not in engineering or technical fields, we help to avert disasters.  If it were not for lessons learned, codes implemented and adhered to, half the world would be on fire at any given moment. – Andy G. I make it possible for companies to do things in their facilities while also enabling workers to return home after work without harm. – Kelly J. My kids are 3 and 5, they think I teach people how to be safe around chemicals. Everyday at dinner they ask me what chemicals I learned about and if you need gloves, a mask or a suit to be around that particular chemical. It's quite sweet. – Carolyn B. I tell them that we help facilities to keep their chemicals in the pipe and not have releases that could cause fire/explosions/injuries.  – Melissa L. I make the plants I do work for a better and safer environment for the workers and the communities around them. – Kelvin S. I describe what I do as "making sure all the processes in various factories and companies around the US run safely so the workers can go back to their families at night". – Joel R.

The high-level goal of the numerous machinery safety standards is to reduce injuries associated with machinery interaction. An additional advantage of applying these standards is the effective identification of hazards and analysis of risk, which can have far-reaching impacts and extensive benefits. What Are They Machinery safety standards are industry consensus standards published by standard development organizations both internationally and within the United States. There is a vast volume of published content for Original Equipment Manufacturers (OEMs), machinery users, and integrators to follow when designing, integrating, or using machinery. The prominent machinery safety standard development organization in the U.S. is the American National Standards Institute (ANSI) B11. The ANSI B11 series consists of approximately thirty documents that focus on machinery and machine tool safety, defining safety requirements for machine manufacturers (suppliers), integrators, and users. The ANSI B11 documents mirror the ISO “type A-B-C” established in ANSI/ISO 12100:2012 (Safety Of Machinery - General Principles For Design - Risk Assessment And Risk Reduction), which categorize the standards into three types: Type A – basic safety standards, providing foundational concepts and design principles applicable to a broad spectrum of machinery; Type B – generic safety standards, expounding upon key requirements for the implementation of safety devices and safeguards applicable across a range of machinery; Type C – machine safety standards, defining detailed safety requirements for specific types of machinery A facility looking to be compliant would first start by applying the Type A standard – ANSI B11.0 and ISO 12100 in the U.S. and internationally, respectively. These comprehensive standards provide a method for risk assessment to quantify the unmitigated risk level for the hazardous scenarios associated with the machine. The Type B standard next establishes appropriate safeguards (e.g., interlocks, area scanners, light curtains, etc.) to effectively achieve an acceptable level of risk for all hazardous scenarios. Lastly, a Type C standard needs to be applied based on the specific type of machinery the organization is manufacturing or operating, in order to meet safety benchmarks that have been developed categorically. Although multiple standards may apply to each specific application and may vary based on operational locations across the world, users can likely find a relevant industry consensus standard to provide a framework for machinery safety due to the large availability of standards developed by the many standards development organizations. OSHA Compliance Machine manufacturers in the U.S. are required to comply with the Occupational Safety and Health Administration, OSHA, health and safety laws. Industry consensus machinery safety standards are a recognition of common safety benchmarks and can be used to demonstrate compliance with the OSHA machinery safety requirements of 29 CFR 1910.212 and the General Duty Clause. OSHA’s General Duty Clause requires an employer to furnish to its employees "employment and a place of employment which are free from recognized hazards that are causing or are likely to cause death or serious physical harm to his employees.” Since machine hazards are “recognized” in industry consensus standards, OSHA expects facilities to conform to machinery safety standards to keep their place of employment free from “recognized hazards” and demonstrate compliance with OSHA requirements. This holds true as long as the industry consensus standard is as strict or stricter than the regulation, which is often the case. Specifically, OSHA has promulgated standards within 1910 Subpart O - Machinery and Machine Guarding, which includes sundry standards applicable to specific types of machinery. ANSI and ASME standards are referenced in addition to numerous other published resources to assist the OEM or machinery user in providing a workplace free from recognized hazards that could potentially cause death or serious physical harm to employees. Compliance with the machinery safety standards is not the only method to comply with OSHA requirements, yet it is both a recognized and approachable method that conforms with OSHA expectations. The machinery safety standards were written by experienced individuals from diverse professional backgrounds to make compliance with OSHA regulations more approachable for manufacturers. Benefits of Applying Machinery Safety Standards The most important benefit of applying machinery safety standards is a reduction of injuries. The standards provide an actionable framework for machine users and manufacturers to reduce the risk of injury through the implementation of safeguards and safe machine design. The standards development organizations publish knowledge at the forefront of safety design and technology, which helps to realize value specific to a wide range of applications. Thanks to this, machinery designers, integrators, and users do not need to reinvent the wheel, saving time and demonstrating business justification while achieving an acceptable level of risk. Applying machinery safety standards is also an opportunity to recognize value apart from safety. If the risk assessment process is conducted early in the design phase, it can be leveraged to integrate controls, automation, and interlocked safeguards into the machinery at an early stage. In general, an opportunity is posed to make cost-effective modifications and implement safe design with a tremendous potential to drive innovation. Furthermore, efficiencies are realized through the implementation of the machinery safety standards such as minimizing downtime and increasing reliability. The standards prescribe safeguarded access for maintenance and inspection activities that significantly decrease machine downtime since the entire machine does not need to be taken offline to interact with it. Work tasks can be safely performed in a protected space while saving time from lockout/tagout activity. An efficient maintenance and inspection ability also maximizes machinery reliability by increasing the preventative maintenance frequency due to the ease of accessing machinery during operation. Plant downtime due to employee injury and/or investigation may further be avoided, along with the associated liability expenses and burdens. There are also softer benefits such as improvements in employee engagement and productivity associated with employment with minimal injuries. When employees feel valued and protected in their workplace, they become more productive, leading to a better workplace and improved safety culture. Minimizing injuries can have cascading effects such as reduced stress, increased creativity, increased employee retention, and greater morale. Conformity with machinery safety standards has tremendous benefits such as reducing injury and liability, leveraging early key design changes, minimizing downtime, increasing machinery reliability, quality, and improving productivity. The machinery safety standards positively recompense designers, integrators and users along with providing a framework for achieving OSHA compliance.

In machine control system design, the question of when to use safety-rated equipment is commonly asked; but this is often the wrong question. The defining question should be whether the specific machine control function is a safety function. Determining this is not always straightforward and requires a hazard assessment to identify safety functions (e.g., equipment, devices, or circuits) and the required performance level of the system's safety-related components. Without a thorough risk assessment, there simply is not sufficient information for a blanket answer on whether it is a safety function or not, and therefore it is not possible to dictate whether or not safety-rated equipment is required. In general, a safety function protects from hazardous scenarios, reduces the risk of personnel exposure to a hazard, and/or maintains a safe state. Some obvious safety functions are emergency stops (e-stops), resets, and protective device integration such as light curtains or area scanners. However, to fully understand the purpose of a circuit or the function that it is performing, personnel involved must have an intimate knowledge of the facility and environment, as well as the specific machines integrated with upstream and downstream systems. The risk assessment is the starting point to characterize tasks, hazards, and operational and control scenarios. It identifies the safety function requirements for the machinery and dictates the required performance level of the safety circuit. Lower performance levels are more commonly achieved with standard equipment, while higher performance levels commonly require safety-rated equipment. For high performance levels, the components involved in the control circuit need to be safety-rated (such as a safety relay or a safety-rated position switch), wired into a safety I/O, and programmed in the safety PLC. However, the use of safety-rated components or a safety PLC does not automatically produce a safe state – the Safety Requirements Specification (SRS) must be adhered to in its entirety to ensure the outcome of the operation being performed will actually reach a safe state. The risk assessment cannot be skipped since it is the critical building block for the SRS and required performance level of the safety functions. An example that demonstrates these concepts is a stop control circuit that has an effect of removing power to a drive. It may be tempting to assume that this is a safety function, but without a risk assessment, there is not enough information to make that determination. For instance, if the drive is a cleaning spray injection blower with a very gentle solution of soap and water and the operator exposure is low, then the resulting risk is very low. This may meet the organization's risk tolerance criteria, and no further action is required. Alternatively, if an acceptable level of risk is not achieved, the risk assessment may determine that the required performance level of the function is a PLa or PLb, which can be achieved with standard control equipment. In summary, safety functions are not always obvious, and a thorough risk assessment is critical to determining whether standard control equipment or safety equipment is needed. Alarms, warning systems, holding brakes, and starting up a backup generator are all examples of safety functions. Understanding the risks associated with a particular scenario and determining the required performance level of the safety functions is necessary to ensure the safety of personnel and maintain a safe work environment. More on Function Safety in Machinery Safety: S1E09: Functional Safety & A top thing to avoid: The term functional safety gets thrown around a lot, but what does it mean? In this episode, the term functional safety is unpacked to understand what functional safety is, what is tells us, and why it is important. Furthermore, the number one mistake to avoid if you are responsible for conformity with functional safety standards is explored.

by aeSolutions' Judith Lesslie Improperly selected and validated IPLs can result in high hazard scenarios that have far less risk reduction in place than you think you have. Implementing a systematic process to properly vet your IPL candidates for the core attributes is recommended. Engaging experienced PHA/LOPA facilitators and having the right team during the meeting is the first step in proper IPL selection. Further validation of IPLs to confirm they meet the defined criteria can be time consuming but also goes a long way toward increasing your confidence in your most important safeguards for higher consequence scenarios in highly hazardous chemical processes. Read the entire article: How to Avoid Independent Protection Layer Selection Errors - ISSSource

“In earning this second certification, maintaining its status of Siemens Process Safety Specialist and continuing to execute successful projects, aeSolutions has demonstrated that they have the engineering and quality practices to implement PCS 7 Failsafe systems correctly the first time utilizing best practices,” said Rich Chmielewski, Siemens USA DCS Solution Partner Program Manager. Read entire story at https://isssource.com/aesolutions-earns-safety-certification/ aeSolutions receives software licensing and training on the newest technologies and best practices as a Siemens certified solution partner, ensuring future-proof solutions. Engineers from aeSolutions took part in an expert workshop to reaffirm best practices as part of their training. aeSolutions will also receive priority hotline support, as well as consulting time with Siemens senior product management, application engineers, and enhanced proposal tools, through Siemens webinars and Partner Portal for existing and new innovations. Siemens facilitates a rigorous, multi-faceted procedure for solution partners to become accredited. Multiple aeSolutions safety projects were reviewed by a Siemens senior consulting engineer from Karlsruhe, Germany, to confirm that project configuration workflow processes met Siemens-documented best practices and international standards. Learn more about our over 20 year partnership: https://www.aesolutions.com/siemens-solution-partner

The analysis of existing gas detection systems has shown that the primary limiting factor in the effectiveness of a system is incorrect detector placement. This factor alone outweighs the probability of failure on demand of the individual system components (sensors, logic solvers, and final elements). Incorrect detector placement can be so detrimental that the system cannot even be credited as an effective independent protection layer. Gas detector location has historically been selected based on rules of thumb and experience. Common rules have been to place detectors: at breathing height for toxic gases one to two feet above ground for gases heavier than air above the leak source, or as high as possible, for gases lighter than air near the ground for cryogenic conditions near air ductwork intakes, or room outlets in areas accessible for maintenance away from locations that can be damaged by general maintenance where to place gas detector The optimal detector location will vary from plant to plant. What is appropriate for a congested offshore platform will be different than for a batch chemical plant with multiple recipes, or a refinery, or a sour production well. Inconsistent approaches have often been found. Existing facilities that have been analyzed have been found to have significant gaps in detector coverage. There has been a growing interest in determining the effectiveness of gas detection systems in a quantitative manner. Our understanding of gas dispersion, and the ability to model and predict the release behavior, has grown significantly. Two approaches have been developed for detector placement; geographic coverage, and scenario-based coverage. Geographic coverage places detectors on a uniform grid. Geographic methods can result in more detectors than are necessary. In addition, geographic methods are based on low or medium reactive materials such as methane or propane. Geographic methods are not suited for high reactivity materials which can achieve a detonation. Furthermore, geographic placements can lead to higher installation and operating expenses. As a result, many companies prefer to use scenario-based coverage over geographic methods. Scenario-based coverage places gas detectors based on computer dispersion modeling. Scenario model selection involves identifying a variety of leak points, hole sizes, and leak directions. The optimal number of detectors can then be placed in the optimal locations. There are limitations of what a gas detection system can reasonably be expected to do, beyond having a highly effective detector coverage. Beyond having a highly effective detector coverage, there are limitations of what a gas detection system can reasonably be expected to do. What is the effectiveness of the mitigation system? To achieve an overall performance of SIL (safety integrity level) 1 or higher, a system would require detector coverage over 90%, and mitigation effectiveness over 90%. To achieve SIL 2 would require both numbers be greater than 99%. This would be over specifying potential performance. ISA-TR84.00.07 advises that a system not be considered an independent protection layer if either value is less than 90%, as SIL 1 will not be possible in such a case. 3D modeling incorporating wake effects from buildings can show a gas plume reaching areas that may not be immediately intuitive, such as air handlers on the back side of a building. Room ventilation patterns may also cause non-intuitive gas behaviors. Using scenario-based coverage dispersion modeling may increase the initial project cost, but it has been shown to offer a lower overall project cost due to reduced detector quantities and reduced maintenance. It also provides a quantitative basis for documenting the rationale behind detector placement decisions. Benefits include reducing life cycle costs, reducing risk to onsite plant personnel, and reducing risk to offsite public receptors. To learn more about this topic, read the full paper “How Can I Effectively Place My Gas Detectors” by clicking here. Learn More about our Gas Detection Services

Inspired by “Conducting an Effective Functional Safety Assessment” presented at 2019 ISA PIC 2019—Process Industry Conference. by Greg Hardin The ISA/IEC 61511 standard defines a functional safety assessment as [an] “investigation, based on evidence, to judge the functional safety achieved by one or more safety instrumented systems and/or other protection layers.” The standard describes five stages where functional safety assessments may be performed: After the hazard and risk assessment has been carried out, the required protection layers have been identified and the safety requirements specification has been developed. After the safety instrumented system has been designed. After the installation, pre-commissioning and final validation of the safety instrumented system has been completed and operation and maintenance procedures have been developed. After gaining experience in operating and maintenance. After modification and prior to decommissioning of a safety instrumented system. The earlier the assessments are done, the sooner potential problems may be identified, and the quicker, easier, and cheaper it will be to implement any potential changes. After all, it’s easier and cheaper to fix things on paper rather than after the system is built. The first edition of the standard mandated an assessment only at stage 3. That’s simply too late to achieve any real benefit. The second edition also mandated stage 4. Stage 4 was added to ensure that assumptions made in the design phase were not unrealistic (as experience has shown they often have been). This also misses the potential benefits that could be achieved in performing stage 1 and/or 2 assessments. But what about a stage 0 assessment? While not covered in the standard, a stage 0 assessment could be used to identify problems even earlier. Stage 0 would be after clause 9 “allocation of safety functions to protection layers”. This would be after safety functions have been identified and SIL targets have been set, yet before detailed specification and design begins. A stage 0 assessment could identify where frequency and/or severity assignments may have been too conservative resulting in the over-specification of safety instrumented functions. One example would be the specification of unusually high safety integrity level (e.g., SIL 3) burner management system purge functions. Similarly, if too much credit were taken for non-instrumented protection layers, the performance of the associated instrumented functions may be understated. A stage 0 assessment could prevent people from avoiding even entering the proverbial rabbit-hole (i.e., starting with an incorrect design) altogether!

Ammonia is used throughout the process industries. However, an ammonia release has the potential to cause health concerns to those on site as well as those in the surrounding community. Safety systems are often implemented to minimize the impact of such a release. A corporate safety review of a brownfield pressurized ammonia storage facility determined that a new leak detection, occupant notification, equipment isolation, and hazard suppression system was required. aeSolutions provided a system that automatically monitors and detects a release, along with weather and wind conditions, and mitigates the effects. This particular system includes point and line of sight gas detectors, product isolation valves, and electronically operated water cannons. Field devices are monitored and controlled using a purpose built aeSolutions FGS 1400 MK II fire and gas panel. The system was configured using SIMATIC PCS 7 and Safety Matrix. The system meets NFPA 72 for fire alarming and mitigation control, and is FM approved to NFPA 72 for fire protection, combustible, and toxic gas measurement. The system is centered around redundant Siemens 410-HF safety certified PLCs with redundant OS servers and two OS clients. The system interfaces with (10) point gas detectors using 4-20 mA signals, (11) laser beam gas detectors using Modbus, and controls (11) isolation valves incorporating partial and full stroke testing, and (14) 3-axis 2,000 GPM water cannons. The water cannons provide 340 degrees of rotational movement, vertical movement, and each has a dedicated flow control valve. The water cannons are used to dilute the ammonia and knock it to the ground, allowing it to be contained in the diked area around the tanks and spheres. Control room personnel are also able to control the spray nozzles remotely. The FGS 1400 MK II Safety Instrumented Fire & Gas System from aeSolutions is a pre-engineered, pre-configured and pre-packaged system that is suitable for a wide variety of applications and is available as a turnkey solution. The FGS 1400 MK II provides the same demanding levels of performance required by the ISA and IEC safety standards for safety critical applications. Learn more about the FGS 1400 MK II Benefits of aeSolutions Fire & Gas Systems: • Scalability provides you with customization options • Listed for use with a wide variety of end devices for maximum flexibility • Customized functionality and listings available • Siemens PCS7 platform integration for increased operator visibility • FM-Listed for Fire & Gas detection and suppression to satisfy regulations • Industrial grade hardware for increased reliability in plant applications • Factory training available to enable end users to maintain their systems • The FGS 1400 MK II is listed for Fire Command Center and proprietary Supervising Station functions. To see how aeSolutions can help you with your unique gas detection and mitigation needs, please contact us. *Updated from earlier post

Due to potential blast hazards to plant personnel, the control rooms of one of the world’s largest natural gas (NG) processing and compression facilities had to be relocated to a Blast Resistant Module (BRM). This complex cutover for personnel protection needed to be completed without shutting down (S/D) either of two interdependent NG production facilities. A S/D would result in a process upset at 12 oil production facilities which rely on the natural gas feed for their operation. Challenge The facility feeds large volumes of compressed natural gas to 12 oil production facilities through sections of piping that are up to 5 feet in diameter with compression being achieved by enormous turbines. The number of drawings, valves, interconnecting wires, and control schemes that needed to be evaluated was extensive and complex. Normal gas operation controls such as turbine controls, panel boards, and valve interfaces such as the main gas header valves feeding the plant had to be migrated which included Basic Process Control Systems (BPCS), safety systems, Fire & Gas (F&G) systems, Halon fire suppressant circuits, and Emergency Shutdown (ESD) circuits. A misstep on these critical systems could have brought the entire facility down which would have cascaded to downstream facilities which rely on the natural gas for their operation. Furthermore, the NG facility equipment spanned 50 years of modifications, and many upgrades which were needed to universalize and modernize the many generations of equipment, including digitalizing hardwired signals into a new PLC-based BPC. The greatest challenge was migrating the hardwired emergency stop (E-stop) circuits to the new control room with minimal transition time and without a widespread outage. In fact, because of the hazards and complexities involved in a complete shut down and restart, the NG facility had only been shut down twice since being placed into service many decades earlier, and it had been over a decade since the last complete outage. E-stops are used by operators as a last resort in response to a critical process excursion. The E-stop circuit, when tripped by the operators, opens valves to the flare relief system, closes isolation valves, and shuts down running equipment. Complicating matters is the fact that E-stop circuits are designed fail-safe, meaning if any circuit is opened, the E-stop actions are triggered. Solution aeSolutions designed the new control room and took responsibility for all stages of the project, managing tasks from conceptual and preliminary engineering to detailed design and managing on-site activity and personnel during the complex cutover. Beginning with a comprehensive survey of the existing facilities, aeSolutions cataloged all equipment and systems that needed to be relocated, identified all stakeholders and resources who would need to be involved, and then created a detailed plan for cutover without requiring plant downtime. Specifically, aeSolutions: Performed a detailed option analysis to evaluate potential best solutions Analyzed existing terminations and every wire to understand what it does and temporary bypasses to be put into place; maintained a well-documented log to track what had been completed Developed step-by-step cutover procedures and checklists and an integrated schedule that identified specific people and detailed daily tasks over the entire year leading up to the cutover of both NG facilities. Impacted stakeholders included facility engineers, operators, support staff, design team, contractors, vendors, construction crew, and IT networking crew. A comprehensive responsibility matrix was maintained to coordinate all tasks at the level of detail required for success. Developed a contingency plan to guard against emergency events and mitigate risk of valves changing position during the cutover process for safety purposes; had personnel man all the valves during the cutover process and used a closed-circuit television (CCTV) system to monitor and detect potential process hazards. Processing natural gas is an exercise in precision, and even the smallest changes in pipeline pressure, flow rates, temperature, and gas composition can have huge impacts Set up a local integration center, i.e., Factory Acceptance Test (FAT) lab, to convene equipment and everyone involved; determined ways to install additional panels; designed, fabricated, tested, and provided the new control panels that were needed for the programmable logic controller (PLC) and control systems as well as safety systems such as E-stops and F&G system; developed a scheme of transitioning existing terminations to new termination locations without causing a S/D; prepared all personnel involved within the FAT lab to ensure a smooth cutover process during implementation in the field Managed on-site activities helping direct the cutover process while implementing the cutover plan, including directing facility operators, engineers, support staff, construction, and even IT staff Result aeSolutions’ role evolved from system integrator to becoming the focal point of coordinating schedules and staffing and choreographing the entire cutover project. aeSolutions started by surveying the existing equipment and systems. By having a single point of contact for project management, the client benefited from standardization of approaches and technology, a higher degree of coordinated activity, and a shortened timeframe. aeSolutions developed an execution strategy and found ways to integrate multiple teams into the plan while handling the conceptual engineering, preliminary engineering, detailed design, and ultimately manufacturing and implementing the required components. The local FAT lab was instrumental in enabling the team to confirm how equipment worked, verify detailed FAT plans and test procedures, and developing methods to quickly (dis)connect test panels with everyone in the same room. Equipment was evaluated during and after the assembly process to verify it was built and operated in accordance with design specifications. The FAT lab provided an off-site opportunity to reconcile and unify all the moving parts involved with the unit before the equipment was shipped to the site. This cost-effective integration strategy saved time and travel costs to successfully cutover the controls on a NG operating plant without impact to production. In the end, the project achieved its two objectives 1) the NG facility employees were safely relocated to the new BRMs and 2) the project was completed without a shutdown or process upset of the operating facilities.

Warren Johnson, senior project manager for consulting, engineering and integration firm aeSolutions, was featured in CONTROL magazine discussing his presentation covering the essential aspects of gas detection system design at the 2019 Siemens Automation Summit. [ In the United States, it’s the role of the Occupational Safety and Health Administration (OSHA) to set limits on employee exposure to toxic and hazardous substances, but it’s up to industry to ensure that those standards are met, said Warren Johnson, senior project manager for consulting, engineering and integration firm aeSolutions, in a presentation covering the essential aspects of gas detection system design at the 2019 Siemens Automation Summit. ‘OSHA doesn’t tell you how to detect gas or how to alarm,” Johnson explained. “It’s up to your engineering group to make it happen.” The presentation and article cover things such as Detector selection & placement,  Architectural aspects to consider, and a bit about the relevant regulations. Read the whole article at www.controlglobal.com Do you have a project you’d like to discuss? Contact Us here

An effective gas detection system protects on-site personnel from toxic and combustible gas releases. Gas detectors that are fit for purpose with the proper technology, measurement level, and location can provide an early detection and warning to personnel to evacuate or take appropriate action in the event of an accidental release. Shortcomings of the Geographic Approach The placement of gas detectors is never a straightforward analysis. A common rule of thumb for hydrocarbon releases (methane and propane) is the 5-meter cloud Geographic Approach; however, this approach is not valid for non-hydrocarbon releases and tends to over-specify the number of gas detectors required. A facility may require a gas detection system for varying chemicals with uncommon properties and parameters. The Geographic Approach does not consider building ventilation, geometry, or obstructions that can significantly impact the dispersion of gas plumes. CFD Scenario Modeling Computational Fluid Dynamics (CFD) scenario modeling is an alternative method to the Geographic Approach that delivers a more accurate number and placement of combustible and toxic gas detectors. Although there is a larger upfront investment, CFD modeling saves costs over the long term by reducing the number of gas detectors required and the expense of their calibration and maintenance. CFD modeling also provides an auditable record of assumptions such as material properties, leak size, leak origin, wind speed, and building ventilation; this can be beneficial in the event of an actual leak incident since the original assumptions can be revisited and revised if the actual leak behavior deviates significantly from the modeled leak dispersion. The CFD modeling results may reveal unexpected behaviors from the vapors of concern compared to what was reasonably predicted. For example, a simple approach might place gas detectors near the roof for gases that are lighter than air. Yet, CFD modeling may demonstrate that ventilation effects pull the gas downward instead, requiring detectors to be placed at lower elevations. In similar fashion, it might be assumed that a remote warehouse building does not require a gas detection system if there are no chemicals of concern within the building; however, a gas leak in another area may disperse farther than expected, resulting in the gas cloud traveling to the unprotected warehouse building. In this case, gas detectors in the warehouse’s ventilation intakes might be advisable. The Takeaway CFD scenario modeling is the best investment for large facilities with specialty gases to ensure gas detectors are appropriately located and perform optimally. It is the most effective tool to have high confidence in protecting personnel from toxic and combustible gas releases, while minimizing the long-term maintenance costs for the gas detection system. Dispersion modeling results may challenge the predictions of simpler, less quantitative methods, and documented modeling assumptions can be referred to and updated throughout the life of the facility.

Those who work in high hazard industries are familiar with the OSHA Process Safety Management (PSM) standard requirements for Process Hazard Analyses (PHA) for their covered processes. These studies are required to be completed initially, then revalidated, typically on a five-year schedule. Good practice implemented at many companies is to follow a similar scheme for processes containing hazardous materials that are not covered by the standard. During revalidation PHAs, among other things, it is expected that any changes or new learnings (from incidents, for example) for the area under study will be incorporated so that the study represents the state of the process at the time of the PHA. It is also expected during revalidation that resolution of prior recommendations will be verified and any safeguards that have been improved or implemented will be integrated and documented. Collecting, reviewing, and incorporating five years’ worth of changes, learnings, and updates to recommendations and safeguards for the process can be challenging and very distracting to a PHA revalidation team. An alternate method of managing PHA review of changes and learnings to a process is to incorporate them into the PHA as changes are underway or learnings occur. This method is often called an Evergreen PHA or Continuous PHA Revalidation. The Benefits Evergreen PHAs have valuable benefits, including: - It is a big time saver at revalidation time since changes, learnings, and the status of recommendations and safeguards are current - The PHA is always current for internal reference, as well as for auditors or regulatory agencies - The PHA always matches the current P&IDs for the process - The preexisting PHA helps teams who are assessing changes to a process to not go beyond the scope of the change and not to issue “wish list” recommendations that are not truly needed to mitigate risks. MOC PHA teams who have a model in an evergreen PHA are more likely to focus on the task at hand. - The preexisting PHA helps teams who are assessing incidents to rapidly translate incident learnings into the PHA in a way that works to align the incident root & contributing causes and consequences with existing information in the PHA. It is most efficient to accomplish this work while the incident investigation participants have the information fresh on their minds, rather than asking a revalidation PHA team to accomplish it perhaps years later. The Challenges Evergreen PHAs are a concept that sounds appealing on the surface, and they do indeed provide many safety and resource benefits. Many sites successfully manage their evergreen PHA in a way that allows them to obtain the maximum benefit from the practice. But if improperly managed or executed, “not so evergreen” PHAs can suffer from failures such as lack of control of the master file and archived files, lack of a designated “owner” of the file, failure to track file updates, or failure to include a change, learning, or updated action status at the right time. These flaws can all lead to confusion and difficulties in management of the PHA. This in turn can lead to suboptimal use of people’s time and in the worst case, misunderstandings about the process hazards and their safeguards. This has the potential to lead to safety gaps and even process safety incidents. Get Off on the Right Foot Start your evergreen PHAs off right by incorporating good practices and good usage discipline in your PHA program, including: - A single designated storage location and “owner” for the file(s) - A narrative, ideally embedded in the PHA file, clearly describing the changes from the baseline or most recent revalidation PHA with relevant MOC, project, and incident references included - Revision tracking methods, including for the file, the nodes that were revised, new safeguards and recommendations, and even the scenarios that were added or revised - Predetermined conventions for how new or revised scenarios and safeguards should be marked as revisions - A tracking method for the status of recommendations and proposed safeguards - A tracking method for new recommendations developed during changes to the baseline PHA or most recent revalidation - A predetermined method for how to incorporate future changes that may be implemented at different times, for example turnaround projects vs. projects that are expected to be completed while a process is running - Retention of old file versions, in the event that a change is canceled before implementation - Provision of updated documentation from the updated PHA to affected staff - A method to familiarize affected staff with the changes made to the baseline PHA or revalidated PHAs If your software product does not currently support the evergreen PHA concept, help is available to improve your templates and even to manage your files and the incorporation of changes in many cases. Properly managed evergreen PHAs can go a long way toward increasing the value of, and your confidence in, one of your most important process safety program elements. Tackle it soon! by Judith Lesslie, CFSE, CSP Process and personal safety professional with more than 35 years’ experience in HSSE leadership, process safety and instrument engineering, project management, and maintenance in the petrochemicals industry.