Updated April 2026 — Imagine discovering a critical flaw in your safety system design before your plant goes operational. This scenario, while nerve-wracking, underscores the importance of early intervention in the design phase. When developing a Safety Instrumented System  (SIS), it’s crucial to ensure that the hardware and software meet the practical needs identified from the initial hazard and risk assessment. That’s the purpose of a functional safety assessment  (FSA). How can stage 1 FSA help discover critical SIS flaws? FSAs, as defined by IEC 61511 , provide a five-stage, evidence-based investigation to judge the functional safety achieved by one or more SIS and/or other protection layers. Stages 1 through 3 of the FSA encompass the SIS  from its original concept through design, construction, and commissioning. Stage 1 specifically takes place after the hazard and risk assessments have been completed and before detailed design work begins, which can help with the early identification of design flaws and safety issues. Here’s what to expect in the Stage 1 FSA process, along with recommendations for a successful outcome. What Are the Goals of a Stage 1 FSA? A well-executed FSA reduces the likelihood of safety incidents. For FSA Stage 1, the primary goal is to verify that the safety requirements specification  (SRS) accurately reflects the needs identified during the hazard and risk assessments. Does what’s on paper reflect the scenario in which the SIS must operate in the real world? Will the SIS actually mitigate the risks identified in the hazard and risk assessment? By ensuring thorough verification of the SRS at this early stage, Stage 1 FSAs help prevent costly modifications and delays later in the project lifecycle. Proper planning leads to smoother project execution, reducing downtime, and increasing overall efficiency. The deliverable for a Stage 1 FSA includes a comprehensive report that presents findings, recommendations, and general observations. It is a good idea to loop in stakeholders to review this deliverable together to align on opportunities to course-correct and next steps. Key personnel include process engineers, control engineers, operations supervisors, and site leadership. What is the Anticipated Time, Cost, and ROI of a Stage 1 FSA? The effort for executing an FSA is minimal relative to the overall project. The initial cost of performing a Stage 1 FSA includes expenses related to document reviews, stakeholder interviews, and detailed analyses. The expense is minimal compared to the total project cost. The duration of a Stage 1 FSA can vary based on the project's size and complexity, typically involving several days of document reviews and interviews with key personnel. Failing to conduct a thorough Stage 1 FSA can lead to incomplete or incorrect safety requirements. This oversight can result in costly modifications, delays, and potentially catastrophic failures once the system is operational. These issues often incur far higher costs than the initial FSA investment. A Stage 1 FSA can help surface the following issues: ●     Incomplete risk assessments ●     Failure to capture safety requirements ●     Insufficient detail in the preliminary assessments. ●     Inadequate stakeholder engagement Conducting a Stage 1 FSA allows for early identification of design flaws and safety issues, which are less expensive to address in the design phase than during or after construction. What is The FSA Stage 1 Process? The FSA Stage 1 process typically consists of the following steps: ●     Hazard and risk assessment verification ●     Verification of safety requirements specification ●     Operational readiness Table: Process Steps for FSA Stage 1 Process Step Objectives   Hazard and Risk Assessment V ●      Review of Hazard Analysis:  Ensure that all potential hazards have been identified and assessed. ●      Risk Assessment Validation: Confirm that the risk assessments accurately reflect the potential consequences and likelihood of identified hazards.   Verification of Safety Requirements Specification ●      Document Review:  Verify that the SRS accurately captures all safety requirements derived from the hazard and risk assessments. ●      Design Verification: Ensure that the proposed SIS design addresses all identified safety requirements and mitigates the associated risks. ●      Cross-Functional Collaboration: Engage with multiple stakeholders to verify the SRS and ensure it reflects the input and expertise of all relevant parties. Operational Readiness     ●      Stakeholder Engagement: Confirm that all relevant stakeholders, including process engineers, control engineers, and operations personnel, are involved in the development and review of the SRS. What Are the Renewable Energy Implications As renewable energy sources reach maturity in the market, the nature of hazards and associated risks change with new unknowns and limited data. Consider the unique explosion and flammability risks of hydrogen, which is relatively new to the market. The hazard and risk assessments for hydrogen facilities  must account for these unique dangers. Similarly, large-scale battery storage systems, essential for renewable energy, can suffer from thermal runaway leading to fires and explosions. Wind and solar farms present risks such as electrical hazards, mechanical failures, and environmental impacts. It is critical that the team conducting the FSA understands the unique hazards. Conclusion Stage 1 FSAs help prevent hazardous events and protect both personnel and assets. Engaging the team actively and addressing potential issues proactively can significantly enhance the effectiveness of Stage 1 FSAs, ensuring the safety and reliability of industrial operations. If you have any questions about your scenario, aeSolutions  is here to provide support. Our team of industry experts are available to help navigate even the most unique challenges.

Updated April 2026 - A Functional Safety Assessment (FSA) is defined by the IEC 61511 standard as an “investigation, based on evidence, to judge the functional safety achieved by one or more SIS and/or other protection layers.” The ultimate goal of an FSA is to make the team confident that their instrumented safety system will reliably achieve the risk reduction needed. While many organizations understand the importance of FSAs, not everyone realizes the significant advantages of conducting one, especially when initiated earlier in the design process. Starting the assessment early allows for more thorough safety considerations and ensures safety measures are ingrained in the project from the beginning. Funct Safety Service Sub Page Why Do You Conduct Functional Safety Assessments? The primary motivation is to ensure the Safety Instrumented Functions being implemented actually address the hazards for which they are designed. It might seem routine, but a Functional Safety Assessment is not just a box to check in your development process; it's a powerful tool that can enhance your organization’s safety, compliance, and cost-efficiency. The benefits include: Safety Assurance The primary and most critical reason for conducting FSAs is to ensure the safety of people, property, and the environment. By identifying and addressing potential hazards, we can prevent accidents and reduce the impact of failures. Standard and Regulatory Compliance: Conducting FSAs helps organizations comply with these regulations, reducing the risk of legal and financial repercussions. Cost Reduction: While implementing safety measures can require an initial investment, it often leads to long-term cost savings. Preventing accidents and failures can significantly reduce downtime, repair costs, and potential liability claims. Innovation and Competitive Advantage : Functional safety assessments can drive innovation by pushing engineers and developers to create more robust and reliable systems. FSA Stages The standard requires 5 stages of FSAs to be performed over the lifetime of a SIS at key phases of the project lifecycle. Stage 1 – After the Hazard and Risk Assessment has been carried out, the required protection layers have been identified, and the SRS has been developed Stage 2 – After the SIS has been designed (typically after Factory Acceptance Testing) Stage 3 – After the installation, pre-commissioning, and final validation of the SIS have been completed, and operation and maintenance procedures have been developed (typically during the Pre-Startup Safety Review) Stage 4 – After gaining experience with the operation and maintenance of the system Stage 5 – After modification and prior to decommissioning of a SIS These stages are sequentially depicted in Figure 7 from ANSI/ISA-61511-1-2018 - Safety Lifecycle Phases and FSA Stages: https://blog.isa.org/hs-fs/hubfs/Imported_Blog_Media/ANSI-ISA-84_00_0-1-2004-IES-61511-Mod-Safety-Life-Cycle.jpg A typical Stage 1 FSA compares the content of the SRS to the hazardous scenario outlined in the risk assessment. For example, Stage 1 will review whether the IPLs are truly independent, whether the SIF will protect against the stated hazard, etc. A Stage 2 will be completed after the detailed engineering is complete and will review the detailed design against the SRS. Identifying and rectifying safety issues at the initial stages of development is significantly more cost-effective than addressing them later in the process or, worse, post-construction. In summary, it’s most cost effective to assess the design while it is still on paper. Late-stage changes can be expensive, lead to project delays, and sometimes even necessitate a complete redesign. In addition to the practical benefits, by addressing safety concerns from the outset, you foster a proactive approach to safety that can be carried forward into future projects, enhancing overall safety awareness and practices. An FSA Stage 3 is done after installation, commissioning, and validation is complete, typically during the Pre-Startup Safety Review. Conducting a Stage 3 reviews work done during the installation and pre-commissioning phases. The Stage 3 FSA ensures the installed system matched the design package. There is now a greater emphasis on FSAs in the standard than previously. IEC 61511 formerly only required the FSA Stage 3 before the introduction of hazards to the process. With the latest version of the standard, FSA Stages 1, 2, and 3 are now required. If the project has advanced beyond the design phase, Stage 1 and 2 can be done congruently along with the Stage 3. By performing FSAs early in your project's lifecycle, you reduce risks and demonstrate your commitment to safety and quality. While these stages of FSAs are a requirement of the 61511 standard, they deliver significant value beyond standard compliance as they provide meaningful advancements towards protecting people and assets. Related: How About a Stage Zero Functional Safety Assessment (FSA)? Don’t Dismiss Stage 4 of an SIS Functional Safety Assessment!

Functional Safety & Bayesian Networks Functional safety engineers fol low the ISA/IEC 61511 standard & perform calculations based on random hardware failures. These result in low failure probabilities, which are then combined with similarly low failure probabilities for other safety layers, to show that the overall probability of an accident is extremely low (e.g., 1E-5/yr). Unfortunately, such numbers are based on frequentist assumptions and cannot be proven. Looking at actual accidents caused by control and safety system failures shows that accidents are not caused by random hardware failures. Accidents are typically the result of steady and slow normalization of deviation (a.k.a. drift). It’s up to management to control these factors. However, Bayes theorem can be used to update our prior belief (the initial calculated failure probability) based on observing other evidence (e.g., the effectiveness of the facility’s process safety management process). The results can be dramatic. For example, ass uming a safety instrumented function w ith a risk reduction factor of 5,000 (i.e., SIL 3 performance), and a process safety management program with a 99% effectiveness, results in the function actually having a risk reduction factor of just 98 (i.e., essentially the borderline between SIL1 and SIL 2). The key takeaway is that the focus of functional safety should be on effectively following all the steps in the ISA/IEC 61511 safety lifecycle and the requirements of the OSHA PSM regulation, not the math or certification of devices. Both documents were essentially written in blood through lessons learned the hard way by many organizations. To learn more about the use of Bayesian networks in functional safety , read the full paper here. Click here to view the complete whitepaper

By Keith Brumbaugh (CFSE, PE) and aeSolutions Technical Team Updated April 2026 - This blog post will examine the concept of taking proof test credit for an unplanned shutdown in order to delay a Safety Instrumented Function (SIF) proof testing deadline. If scheduled outages go according to plan, this is unnecessary; however, when an outage gets postponed, credit for the unplanned trip may be needed to confirm the SIF still achieves its target risk reduction. Safety Instrumented Functions (SIFs) are required to be proof tested at specific intervals (expressed in months or years) in order to justify the calculated probability of failure on demand. Proof tests are performed to detect dangerous covert failures, which can render the SIF inoperable when it is most needed during a hazardous event. These proof tests are given a specified amount of coverage expressed as a percent of the dangerous failures detected vs total failures (detected and undetected). A proof test is typically undertaken during scheduled plant outages (for example, a turnaround). Unfortunately, the timing of an outage often shifts due to external circumstances. If the calculated SIF proof test interval is equal to the outage timing, then delaying an outage could result in a SIF that is no longer meeting its calculated probability of failure on demand. If the delay is long enough, the SIF could potentially fall below its performance target. This could result in the plant operating with an unmitigated risk gap. The concept of taking credit for an unplanned shutdown boils down to the fact that during an unplanned shutdown, all devices will typically trip and move to their safe state. This would apply to almost any SIF’s final elements (typically a valve or a pump). Using valves for example, many SIF valves are fail closed. If the air is vented from the actuator, or if the power is removed, the valve should close. If a final element is able to transition from the operating state to the safe state, and the transition can be proven, this is proof of the final element’s ability to function on demand. This actuation can be assigned appropriate coverage credit, and the credit can be applied to satisfy part of the SIF proof testing requirements, allowing for a delay in the full proof test.   What devices can we take credit for? When determining what devices to credit in a trip, we need to examine what sensors, logic solvers, and final elements were involved. The first question we want to answer is what caused the trip: the SIF sensor or something else? For the logic solver, we need to determine how the trip was commanded. For the final element, we need to figure out what moved (or stopped moving). Typically SIF sensors will not be demanded during an unplanned shutdown. These devices are monitoring for a process upset. Unless the source of the unplanned shutdown was due to a process excursion involving the actual SIF, then the SIF sensor will be reading normal during the trip. Consequently, there would be no proof of the successful function of the sensor. Fortunately, this is not typically an issue as sensors are rarely the driving factor in a SIL calculation. For final elements such as valves, the valve body can almost always receive credit as long as it moved. The actuator, solenoid, and positioner will need a closer look, as well as the mechanism performing the trip of the valve. The user needs to consider what form of actuator and solenoid (or other positioner) was involved in the trip. This particularly makes a difference when a smart SIL-certified positioner is used rather than a solenoid. If the SIS logic did not demand the trip, it is possible the solenoid never moved and thus would not receive credit. On the other hand, when a valve uses a SIL-certified positioner, these are often driven to 0% during a shutdown by either the SIS logic solver, or even requested by the BPCS logic solver. Solenoids and positioners operate differently, so moving a positioner is not the same as breaking the circuit of a solenoid. The same concepts apply for other types of final elements. For example, for equipment driven by a motor, we need to figure out if the motor was stopped by the SIF relay or a BPCS relay.   How much credit can we take? The next important question we need to answer is how much coverage credit we can take. Crediting the equivalent of a full stroke proof test is not recommended for an unplanned shutdown. In SIL calculations for valves, varying amounts of credit are given depending on whether you are performing a full stroke test or a partial stroke test, with the amount of credit determined by the robustness of the test. For example, a full stroke proof test could provide 90% proof test coverage, particularly if a leak test is performed. A partial stroke test might give 60% credit for moving the valve a minimal amount closed and then back open within a few seconds. As it can be reasoned, the partial stroke would detect only a subset of the failures that would be detected by the full stroke proof test. Because the partial stroke test only strokes the valve a portion of the total travel possible (and doesn’t fully close it), the partial stroke test would tell nothing about the integrity of the valve seat and associated leakage. The amount of credit possible due to an unplanned trip will not be the same as a full stroke proof test credit. The practitioner would need to examine what portion of failures would be detected during an unplanned trip (much like the partial stroke test). For example, the practitioner might assume the valve moved from the unsafe state to the safe state during the shutdown, but this would need proven. They might look to see if there is valve position feedback, including possibly a physical valve inspection at the time of the trip. If the practitioner does not have any indication that the valve moved, then it’s not possible to say the valve actually did. It is possible some other equipment brought the process to the safe state independent of the valve. Without feedback of the actual valve, the practitioner will never know if the valve actually moved. For motor driven equipment, positive indication of motor stoppage should be examined. For other types of final elements, such as electrostatic precipitators, credit for an unplanned trip requires verification by other means.   Other Considerations Finally, we should confirm our devices are still operating within their design parameters (e.g. have they exceeded their manufacturer recommended replacement interval). Useful life is typically provided by the device vendor and has various connotations, one of which is how long a device’s failure rates are considered valid. If useful life is exceeded, the device may no longer have the same failure rate assumed in the SIL calculation. Useful life is typically longer than the proof test interval, and it becomes more relevant to this discussion as the devices ages. If the useful life will be expended by the next planned test, and the credit for the unplanned shutdown will push the turnaround beyond the useful life, then the device should be replaced during the unplanned shutdown. In summary, credit can be taken for an unplanned shutdown, but there must be careful consideration of the circumstances and justification. A primary concern in this process is that over crediting the test can lead to non-conservative results and additional risk. The practitioner must understand the mechanics of the unplanned shutdown to ensure appropriate credit is taken.

Updated April 2026 - We can help you pick up your PHA/LOPA which maybe been put to the side and provide the services to set you up for the safety system design phase. Standard SIS deliverables include the review of specification, confirming that the SIL levels are what they should be, and that the proof testing procedures are correctly documented to support your regular testing intervals.  Transcript: "aeSolutions has a full suite of offerings and the safety lifecycle, from the PHA LOPA aspect in the upstream design all the way through into the detailed engineering phase. Our group SIS engineering (Safety Instrumented Systems) sits kind of right in the middle between the two, you have the PHA LOPA upstream and you've got the detailed design downstream. We take what the PHA LOPA outputs. We massage it a little bit to get it into a more meaningful list of safety functions, for example. And then we can take that through the conceptual design phase where it goes into SIL calculations and SRS's and cause and effects and gets that into a into a package that can ultimately be handed downstream into the design phase. Everything we do here is developing standard SIS deliverables by making sure that all the specifications are correct. All the safety integrated levels are what they should be. All the proof testing procedures are correctly documented. So that our clients can have regular testing intervals with the necessary equipment that they need to be testing. One of the things that we've seen a lot of our clients do is they'll do the PHA LOPA and then they'll take that information and they'll essentially file it away and do very little else with that. And one of the challenges that we've seen is the SIS needs to be designed against that document and so we can take that document either from an internal study or from a client and help pick it up and do the rest of the upstream engineering on it. Where we identify, what are your safety functions look like, how many sensors o you have? And get that into a more defined safety function that can ultimately be? Hand it off to the design team. The other aspects that we run into is a lot of times I'll do the front end engineering all the way through. You know, for example an SRS data sheet, but then they don't do things with it and ultimately the intention behind that is not only to use as an operating manual for your safety function, but you also want to use that as the guiding document in the design phase so that you ensure that everything that you're doing in the design. This matches what you intended it to do on the on the front end."    PHA LOPA Process Safety

by Keith Brumbaugh , P.E., CFSE ​ Achieving Safety Integrity Level (SIL) targets can be difficult when proof test intervals approach turnaround intervals of five years or more. However, some process units have planned and predictable unplanned shutdowns multiple times a year. During these shutdowns, it may be possible to document that the safety devices functioned properly. This can be incorporated into SIL verification calculations to show that performance targets can now be met without incorporating expensive fault tolerance , online testing schemes, etc. This can result in considerable cost savings for an operating unit. The problem If a process plant is following the ANSI/ ISA 84.00.0 1 process safety lifecycle (i.e. ISA 84) or similar, as part of the allocation of safety functions to protection layers phase, a SIL assessment (e.g., a Layers of Protection Analysis (LOPA)) would be undertaken to assign Safety Integrity Levels (SIL) targets to a Safety Instrumented Function (SIF) . A scenario could occur in the design and engineering phase of the ISA 84 safety lifecycle when performing the SIL verification calculations, that the team discovers the SIFs do not meet their performance target. Assuming the calculation was done properly using valid data and assumptions, something would need to change in order to meet or exceed the required performance targets. This issue could occur in a Greenfield plant when first designing a SIF, but is more likely to be discovered during a revalidation cycle of a brownfield plant. Click here to view the complete whitepaper

Updated April 2026 - Written by aeSolutions Technical Team - Some companies implement intermediate tasks during the analysis and design stages of an IEC/ISA 61511 Lifecycle Project with names such as “IPL Select” or “ LOPA Reconciliation”. The result of such studies is often a “refinement” of the control and/or safety system. Examples have ranged from identifying additional final elements to avoid the hazard, eliminating the use of shared instrumentation between protection layers, addressing response time issues, and assessing control system protection layers for full independence of a function against the initiating event and other protection layers. The benefit of such studies is that it’s easier and less expensive to make necessary changes to systems while the design is still on paper. It’s very expensive, and in some cases not even possible, to make design changes after systems have been installed. In the end, it all boils down to people. It is imperative that all personnel be competent in their roles within the Safety lifecycle. New people entering the industry need an opportunity to learn. Yet they need training, mentoring and reviews of their work in order to prevent systematic failures from creeping in and causing accidents. To read more examples of systematic failures throughout the lifecycle , and to learn how to reduce them, read the full paper “Methodologies in Reducing Systematic Failures of Wired IPLs” . Process Safety & Risk Management Industrial Safety Instrumented Systems

by aeSolutions Technical Team & Tab Vestal ​ Updated April 2026 - The history of high consequence incidents in industry reveals that most accidents were the result of systematic failures, not hardware failures. However, a higher degree of focus in engineering is often on the quantifiable failures of hardware. Process Safety risk gaps are often closed or reduced by several types of Independent Protective Layers (IPLs). Two common types are Safety Instrumented Functions (SIFs) and Basic Process Control System (BPCS) functions. The SIFs typically reside within a SIL-rated programmable logic controller, and their achieved quantitative performance is calculated based on random hardware failures of the SIF hardware components. Conversely, BPCS protective layers are assigned generic industry-accepted probability of failure credits. The BPCS generic industry-accepted probabilities of failure are conservatively assigned and consider unquantifiable human-induced systematic failures. In either case, the likelihood of systematic failures can be reduced by recognizing design, specification, maintenance, and operations activities that are potential sources, and applying measures to prevent or reduce them. By reducing systematic failures, you reduce the risk in the industrial process and increase confidence in meeting the intended integrity requirements. This technical paper will discuss the common sources of systematic failures and preventative or mitigative measures to prevent their occurrence. Topics Included in Whitepaper: Systematic failure , random hardware failure , Independent Protective Layer, IPL, SIF, SIS, BPCS , common cause, Human Factor Analysis , SIL Verification Click here to view the complete whitepaper

Updated April 2026 - Those who work in high hazard industries are familiar with the OSHA Process Safety Management (PSM) requirements for routine Process Hazard Analyses (PHA) for their processes. Hazard and Operability (HAZOP) and Layer of Protection Analysis (LOPA) are recognized methods for PHA. LOPA is widely used as a semi-quantitative method to identify, assess, and improve the most effective safeguards for higher consequence scenarios identified in a qualitative HAZOP study . One of the important products of a LOPA is a list of Independent Protection Layers (IPL) . When correctly identified, IPLs are devices, systems, and actions that are capable of preventing a hazard scenario from proceeding to the undesired consequence. In layman’s terms, they are the “best” and most effective of the safeguards that were identified in the HAZOP for specific scenarios and initiating events. The core attributes for safeguards to qualify as IPLs are well-known and have criteria including: Independent of the initiating event and of other protection layers Specific to the hazard Functional, dependable, and reliable (including routine testing) Auditable Secure Subject to management of change There are many reputable sources for training for the HAZOP and LOPA methods. Many organizations also have good internal guidance on this subject. But what happens when inadequate guidance, training, or discipline for the correct use of LOPA and identification of IPLs is present? You might be surprised at how often safeguards not meeting the core attributes are specified as IPLs in industry. It’s easy to find advice detailing the complexities of proper IPL selection and management, but without a facilitator well-versed in the basics of IPL selection, LOPA teams can get off on the wrong foot. The Challenges Many companies and LOPA practitioners employ excellent practices to identify and validate IPLs during LOPA. However, it is surprisingly common for significant IPL selection errors to be encountered during externally facilitated revalidation PHAs, audits and other types of process safety reviews. IPL concerns of the following types are entirely possible to occur in LOPA studies if initial selection or follow-up IPL validation is not as it should be: Use of two or more relief devices, all taken with two or more IPL credits. Relief devices are often a highly effective safeguard. However, they are subject to concerns that should limit the credit taken at times, including use in services where "pluggage" or other common cause failures are credible, engineering assumptions on sizing are not as the PHA team assumed, poor-quality or no routine inspections are performed, and other issues. Use of instrumentation whose failsafe failure modes are opposite of that assumed by the PHA team, which may result in an unrecognized IPL failure to the dangerous mode. Selection of one facet of an IPL such as a BPCS alarm, without recognition that other facets are also needed for a complete IPL, such as alarm prioritization and management, training in the specific alarm response, an operating procedure, and proper field instrument functional testing. Selection of a BPCS alarm and Operator response as an IPL, without confirming that sufficient time is present before hazard development to evaluate and respond effectively to the alarm. Selection of IPLs with insufficient independence from the initiating cause of a hazardous scenario, or insufficient independence from another IPL for the same scenario. A classic example of this is selection of an instrument to alarm or interlock of a process condition that could be initiated by a failure of that same instrument. Crediting design pressure and temperature ratings; both are equipment attributes that should normally be taken into account in identifying the scenario consequences, not credited as an IPL. Building Confidence 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 strongly 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.

Updated April 2026 — Authored by Carolyn Bott — A Process Hazard Analysis (PHA) will prove to be the cornerstone of Process Safety Management (PSM) at any operating facility with the correct tools and the right leaders. Although there are many variables concerning PHAs, the process can be simplified and impactful results can be attained. In this blog, we delve into the 5 facets of an efficient process hazard analysis (PHA). Process Hazard Analysis Scope A well-defined scope for a Process Hazard Analysis is critical to identify potential safety and environmental hazards in a facility. Having a clear and defined Process Hazard Analysis scope does the following: Sets the boundaries of the analysis - This assures all necessary elements are included and relevant risks are identified and assessed Enables the Process Hazard Analysis team to focus on specific areas of concern and analyze them in detail - This reduces the potential for error and minimizes both the time and resources needed Ensures that all stakeholders are aware of the objectives and outcomes of the PHA Standard for Approaching a Process Hazard Analysis Different companies may have their own specific Process Hazard Analysis standards, specific to their operations and the risks involved. These standards typically outline essential measures to perform a thorough PHA, including: Qualifications and training required for team members Selection of appropriate methodologies Level of detail required in the analysis Documentation requirements for the study Frequency of review Ongoing monitoring requirements ensuring the safety and efficiency of operating processes Adherence to these standards is typically required by regulatory bodies and industry best practices. A standard can ensure all relevant factors are considered and a thorough analysis is conducted. Following a standard also facilitates communication and collaboration among stakeholders, enhances consistent decision-making across sites, and promotes continuous improvement in a site’s process safety. Process Hazard Analysis Team An effective Process Hazard Analysis team is composed of individuals with diverse expertise, including engineers, operators, maintenance personnel, and safety professionals. The team: Shall have expertise in engineering and process operations Shall include at least one employee who has experience and knowledge specific to the process being evaluated One member of the team must be knowledgeable in the specific process hazard analysis methodology being used Must be able to work collaboratively to identify hazards, evaluate risks, and develop appropriate risk management strategies Effective communication and teamwork are vital for a successful and efficient PHA. The proficiency of the PHA leader or facilitator has a substantial impact on the team and the outcome of the PHA. A facilitator leans on their own risk management experience and is responsible for guiding the team through the identification and evaluation of all credible process hazards. The leader continuously assesses the team’s dynamic and intervenes when necessary to ensure the group remains on task to complete the PHA efficiently with impactful results. A company can utilize in house experts or hire a third-party to shepherd their Process Hazard Analysis needs – Process Safety Consulting Process Hazard Analysis Techniques & Tools Methodologies The methodology selected must be appropriate to the complexity of the process and site standards. One or more of the following methods, as appropriate, may be used to determine and evaluate the hazards of the process being analyzed: What-if Checklist What-if Checklist Hazard and operability study (HAZOP) Failure mode and effects analysis (FMEA) Fault tree analysis An appropriate equivalent methodology For more info on choosing a risk assessment methodology, check out our webinar that examines the advantages and limitations of various methodologies: Choosing a Risk Assessment Methodology Tools Computer-based systems are used to document Process Hazard Analysis discussions in an organized manner and provide consistency throughout the analysis. Examples of PHA documenting software include: Sphera® PHA-Pro® PrimaTech PHAWORKS RA® aeShield® aeFacilitator® Using appropriate software eases the execution of risk studies. Process Hazard Analysis Review Cycle All Process Hazard Analyses must be updated and revalidated every five years. The periodic review should reflect any changes in the process or surrounding environment that may impact safety. An alternate approach to managing PHA updates is to incorporate them into the study file as changes occur. This method is often called an Evergreen PHA or Continuous PHA Revalidation. An efficient and effective PHA can enhance the safety of processes, reduce the risk of accidents and incidents, improve compliance with regulations and standards, and ultimately support the organization's goals and objectives. Ensuring these five (5) components are in place can help companies have an efficient PHA to identify and mitigate risks before they become safety incidents. The Takeaway | 5 Facets of an Efficient Process Hazard Analysis Summarized Clear and well-defined scope that is relevant to the system being analyzed Systematic and structured approach Multi-disciplinary team of subject matter experts who can identify and evaluate potential hazards from different perspectives Use of appropriate techniques and tools to evaluate and prioritize risks Periodic reviews and updates If you need more guidance for your Process Hazard Analysis, please feel free to reach out to aeSolutions to speak with one of our PHA experts about our capabilities. Click here for more information on aeSolutions' HAZOP Study services

What’s a HIPPS and where are they used? Updated April 2026 - There are two common applications for a High Integrity Pressure Protection System (HIPPS) . First, many process facilities have expanded to the point where the original pressure relieving and flare system may no longer be able to handle a potential event. Preventing a potential overpressure through the use of a HIPPS can be done at a much lower cost compared to installing a new flare and header system. Second, many subsea and land based pipelines are not designed to withstand full wellhead pressure. So a HIPPS measures pressure (usually using redundant transmitters), utilizes a logic solver (many technologies and configurations are acceptable), and closes valves. While such designs are allowed per current codes, the justification of such a system requires careful analysis by a team of specialists. The justification and analysis of a HIPPS must consider all operating and upset conditions that might cause an overpressure. Process dynamics must be analyzed to determine if the HIPPS can respond quickly enough to prevent the hazard. Some cases may be quite complex with multiple scenarios and multiple HIPPS. Without an adequately sized conventional relief system, the HIPPS represents the last line of defense against an overpressure event. Subsequently, many end users require an independent, third party review of the justification of such a system. How good is good enough? A HIPPS should offer performance as good or better than the conventional relief system it may be replacing. The performance of relief valves in the process industries varies considerably depending upon the application. Published sources of data show that relief valves in some applications offer performance no better than the equivalent of Safety Integrity Level 1 (SIL 1). Considering the uncertainty of the data, many specify that HIPPS meet SIL 3 performance. This requires the use of fault tolerant sensors a nd valves. The use of a SIL 2 system is still a possibility, with significantly lower capital and operational costs. Questions to ask yourself Do you have a case where the existing relieving system is unable to adequately handle the load, and has this been documented in a thorough hazards analysis? Is the vessel in air, water or steam service? (If yes, the use of a HIPPS is not permissible.) Is approval of local authorities required? Do you have a case where a pipeline is not rated for the full wellhead pressure? Have you performed a SIL selection study to determine the level of performance that will be required by the HIPPS? aeSolutions is here to help aeSolutions can help you determine whether a HIPPS is a viable option for your application. If justified, we can work with you to develop the requirements specification and deliver a system that will meet your specific safety and cybersecurity needs. #HIPPS Click here for more information on aeSolutions' pressure relief study services

By Chris Hickling Updated April 2026 - A Fire & Gas System (FGS) philosophy provides a solid foundation for the design of an effective gas detection system, which in turn helps protect plant and personnel from gas releases and resulting flammable and/or toxic effects. An FGS philosophy for a process facility that is not fit for purpose or does not have a firm auditable basis can increase the likelihood of undetected leaks incurring risk to personnel or unnecessary expenses for the company. Under-engineering a gas detection system has safety implications, while over-engineering has commercial implications such as increasing capital and maintenance costs without significantly reducing risk. The workflow for an FGS philosophy can be summarized in the following steps: Assess FGS requirements – review regulatory requirements, corporate standards, pertinent Process Hazard Analysis (PHA) recommendations, and Recognized And Generally Accepted Good Engineering Practices (RAGAGEP) Develop FGS philosophy and procedures – review materials and properties (flammable, toxic, or inert), process flow, and risk tolerance criteria Define FGS scenarios and zones – determine hazards using data for process conditions, weather, occupancy, and airflow data, and drawings such as plot plans, Piping & Instrumentation Diagrams (P&IDs), and Cause & Effects (C&Es) Define zone FGS performance requirements – Develop criteria to assess facility layout and define areas Develop criteria for FGS detector placement What makes an effective FGS philosophy? Firstly, it's important to establish the scope of the FGS system. Is it intended to protect on-site personnel and equipment, offsite community, and/or environment? A comprehensive review of the entire facility is essential – if individual process units at the facility are exclusively analyzed for gas detection, it could result in a fractured response and unforeseen effects at other units. A gas cloud doesn't care where it's released or where it's going, and it doesn't respect boundaries. Secondly, the FGS philosophy should follow applicable codes like NFPA 72 and be applied consistently across the facility. Issues could arise if different areas of the plant use different gas detection technologies or alarm levels; for example, if one unit of the plant alarms at 10% of the Lower Explosive Limit (LEL) and another unit alarms at 20% LEL, or there are inconsistent color of warning strobes for a toxic gas release. Consistency in gas detection, alarms, and encompassing standardized procedure(s) helps the operators and employees respond efficiently. Additionally, the FGS philosophy should lay down the criteria for decisions on gas detection required and appropriate mitigative response such as alarm levels (e.g., alarm at 10% LEL). The FGS philosophy also helps decide the voting criteria for the number of gas detectors to take action. For example, two out of two (2oo2) gas detectors may be required to alarm before starting the sprinkler system or dumping Halon. Finally, an FGS philosophy should be auditable. During its development, assumptions are made which feed into how the gas release is modeled and location of gas detectors. If a bad assumption is made and a leak later occurs, it is essential to be able to revisit the original FGS philosophy and assess the original basis for the design. If the gas detection system has a performance-based design, the layout of the system is documented so that it can be reviewed and adjusted. Traditional rules of thumb gas detector placement do not offer this ability to review and update the basis. Once these practices are incorporated into a facility's FGS philosophy, a comprehensive and well-documented FGS philosophy provides a solid foundation for the design of an effective and auditable gas detection system. Facilities can have a dependable basis to ensure an appropriate number of gas detectors in the appropriate locations, potentially lowering risk and minimizing costs for the gas detection system. Click here for more information on aeSolutions' SOP Training and Development services