K. E. MCINTUSH, E. M. PULFREY and R. JONES, Trimeric Corp., Buda, Texas (U.S.); and S. MONDAL, Beacon Process Safety Services, Sulphur, Louisiana (U.S.)
Insurance companies are increasingly requiring refineries to show capability of remote isolation of flammable and toxic process streams to minimize a spill or release during a process emergency. API Recommended Practice (RP) 553, “Refinery valves and accessories for control and safety instrumented systems, Section 8,” provides guidance regarding the installation of emergency block valves (EBVs), actuator selection, fireproofing and control stations. The guidelines include the consideration of characteristics of the contents of process equipment and piping, such as toxicity and flammability of those contents. This article discusses the requirements of Section 8.1 (EBV General Installation Guidelines) and reviews additional industry information that can be used to aid in interpreting or using some of the API RP 553 definitions.
Investigations in the use of emergency valves. Insurance companies have been increasingly requiring refineries to install isolation valves that can be remotely operated to avoid major losses during emergency events such as liquid hydrocarbon spills, flammable or toxic gas releases, and fires. Investigations into some major industrial accidents have determined that the ability to remotely isolate sources of the release would significantly reduce the impact of fires that would otherwise cause massive damage and personnel exposure to toxic material. The following examples demonstrate how EBVs could have been used to lessen the impact of the safety incident.
In February 2007, the Valero-McKee refinery in Sunray, Texas (U.S.) experienced an estimated $50 MM in direct losses due to a liquefied petroleum gas (LPG) fire in the propane deasphalting (PDA) unit. A failure of an out-of-service dead leg caused the release of 4,500 lbs/min of liquid propane, and operators could not access the manual isolation valves located inside the battery limits. The U.S. Chemical Safety and Hazard Investigation Board (CSB) concluded that remote EBVs could have significantly reduced the amount of propane that leaked out and, in turn, reduced the size and duration of the fire.1
The Valero-McKee incident is not an isolated event. For example, on April 2, 2019, an incident at the KMCO LLC facility in Crosby, Texas (U.S.) resulted in a worker fatality and 30 injuries, two of which were serious. One of the three safety issues listed in the CSB investigation report was the inability for workers to close the actuated block valve upstream of the release point from a safe location.2
After the Valero-McKee incident in 2007, updates were made to the API RPs regarding remotely operated shutoff valves (ROSVs). Later in October 2012, the 2nd Edition of API RP 553 provided guidelines for installing EBVs for equipment containing flammables and toxic materials.
This article reviews Section 8.1 of API RP 553, which focuses on EBVs and their purpose. Subsequent sections of this work supplement the API RP 553 guidelines, address potential questions and provide interpretation of definitions. Flowcharts summarizing the results of the analysis in this article can be found at the end.
EBV definition and intended functionality. In different industry standards, valves used to isolate hazardous materials are referred to by different names, such as emergency isolation valves (EIVs), safety shutoff valves, cutoff valves, safety instrumented valves, etc. For consistency, this article will refer to these valves as EBVs.
EBVs are designed to control a hazardous incident3 by isolating the flow of flammable or toxic substances in the event of a process upset or emergency, such as a leak or fire.1,2 EBVs can be different types of valves, such as a gate, butterfly or ball, and may/may not have an actuator (for remote operation), depending on the type and situation. For example, a valve located outside the battery limits of a unit may be safe for manual operation in the event of a fire.
This article discusses Type D EBVs, which are remotely controlled from a minimum distance of 40 ft from the source of the leak, located outside the fire zone and designed for safe operation in the event of loss of containment.
EBV location requirements. The location recommendations of EBVs can be determined by the following guidelines in Section 8.1 of API RP 553.3 Subsequent portions of this article will detail supplementary information to provide a more concrete idea of the recommended locations for EBVs.
Compressors (Section 8.1.1):
EBVs are required on 200-horsepower (hp) or larger compressors handling flammable or toxic materials.
EBVs are required on all suction and discharge lines.
EBVs are required in between stages and interstage equipment if the interstage equipment holds > 1,000 gal of liquid.
Pumps (Section 8.1.2):
An EBV is required upstream of the pump if the upstream vessel contains > 2,000 gal of light ends, or hydrocarbons above their auto ignition point or above 600°F (315.5°C).
An EBV is required upstream of the pump if the upstream vessel contains > 4,000 gal of liquid hydrocarbons.
An EBV is required downstream of the pump spillback in the case of high discharge pressures for reverse flow overpressure protection.
Vessels (Section 8.1.3):
An EBV is required for vessels containing light ends or toxic materials. Flow from these vessels should be isolated from potential leak sources such as pumps, compressors, heat exchangers and fired equipment.
An EBV is needed for vessels containing liquids that are heavier than light ends, but above the flash point.
Heaters (Section 8.1.4):
An EBV is required for each fuel gas or fuel oil line to fired heaters and boilers. At least one EBV outside the battery limits for each fuel gas or oil line is typically specified.
An EBV is needed for each process-side feed line to a fired heater that contains flammable fluid.
Applying the RP. It is necessary to understand the sentiment of API RP 553 Chapter 8 and the goal to prevent a large loss of containment leading to ignitable vapor clouds/large pool fires or exposure to acutely toxic materials.
During a refinery evaluation to determine locations for EBVs, some guidelines and recommendations needed further definition to determine if an EBV was recommended by API 553. In the following sections, situations where further definition was needed to develop the EBV installation recommendations are discussed.
Compressors. The compressors’ section leaves room for interpretation of the recommendations. The second bullet point under compressors above (EBVs are required on all suction and discharge lines) is written as an independent guideline and implies that EBVs would be recommended on the inlet and outlet of any compressor, regardless of size or type of material handled. The application of this bullet point is actually dependent on the first bullet point being true. The meaning of the first two bullet points together becomes “EBVs are required on all suction and outlet lines for compressors 200 hp or larger, handling flammable materials.” This issue was not found in the other equipment recommendations, as each bullet point is independent of others.
An issue not discussed in this section is the potential problem of having an EBV on the suction line to a compressor. For example, if the fail position of an EBV on the suction of a compressor is designated as fail-closed, the action could cause significant and costly damage by surging a compressor. Before EBVs are placed into any location, a process hazard analysis (PHA) should be performed to determine the risks and benefits.
Pumps. The language in the pumps section of API RP 553 Chapter 8 is straightforward except for a definition of “light ends” and “high-discharge pressures.” The term “light ends” is discussed in a below section.
High-discharge pressure that may cause reverse-flow and an overpressure scenario cannot be given a blanket definition. An analysis should be performed on the system, looking at upstream equipment to determine if reverse-flow, due to a pump failure or other cause, can lead to overpressure, mechanical failure and loss of containment. The co-authors’ company knows of parties that, based on their internal analyses and standards, define high-discharge pressure as a few hundred to several hundred psi above the suction pressure.
Vessels. The vessels section of Chapter 8 is less defined than the other sections and may lead to difficulty in determining if an EBV is needed. This will be the subject of much of the discussion and examples in this article.
Light ends. The first bullet point in Chapter 8 contains the term “light ends.” While this term is not defined in Chapter 3’s terms and definitions of API RP 553, research, including consultation with industry professionals, has resulted in a working definition that light ends are generally defined as flammable hydrocarbons having boiling points equal to or lower than that of normal pentane, 97°F (36.1°C). This definition is consistent with the one provided in the Handbook of Petroleum Refining Processes, which defines light ends as hydrocarbons with equivalent boiling points ranging from C1–C5.4
Toxic materials. The first bullet point in Chapter 8 also mentions toxic materials, a term defined in Chapter 3 of API RP 553 as:
“A liquid or vapor that can cause harm to humans, with an established exposure limit [either material threshold limit value (TLV) or occupational exposure limit (OEL)] set by a relevant regulatory agency [e.g., the U.S. Environmental Protection Agency (EPA)]. These substances can lead to significant negative effects (such as severe inflammation, shock, collapse or even sudden death) if humans are exposed to sufficiently high concentrations for extended periods. Examples include, but are not limited to benzene, xylene, butadiene, chlorine, ammonia, hydrogen sulfide and hydrogen fluoride.”3
It is important to note that specific concentration limits within the process are not provided. Therefore, the impact of potential leak sources and the volume of toxic materials that may leak should be assessed through a process safety analysis. For instance, a Pasquill-Gifford dispersion model can be applied to evaluate the formation of a vapor cloud containing hazardous levels of hydrogen sulfide (H2S) during a leak. The results of such an analysis should also be reviewed—while a vapor cloud with a maximum H2S concentration of 15 ppmv may not be lethal, it still exceeds the OEL, and a risk-ranking of this scenario in a PHA may result in no actions being taken.
Additionally, it is essential to differentiate between the concentration of a toxic material in a process stream, and the concentration personnel might be exposed to during a spill. The 2018 paper, from the Mary Kay O’Connor Process Safety Center, “PHA guidance for correlating H2S concentrations in process streams to severity of adverse health outcomes in the event of a leak,” states that large liquid leaks (2 in. or greater) may result in personnel being exposed to at least 140% of the H2S concentration in the process stream. This higher H2S concentration from a liquid leak is due to H2S evolving at a higher rate than hydrocarbons and due to liquid leaks having a larger mass flowrate than vapor leaks, leading to more H2S in the air. This analysis was performed with a mixture of n-hexane and H2S.5 is the results are dependent on what liquid is leaking, and the vapor/liquid equilibrium of the process fluid should be modeled to determine the concentration of H2S that will be present in the vapor space above the liquid leak. In general, assuming a constant weight percentage of H2S is present, the heavier the hydrocarbon, the higher the concentration of H2S present due to a leak, as less of the hydrocarbon will flash.
The article from the Mary Kay O'Connor Process Safety Center also provided examples of H2S concentrations in process streams and the corresponding H2S concentrations in nearby breathing zones. For instance, consider a vessel that contains 5,000 gal of n-hexane with a concentration of 1,000 ppmw of H2S and a 2-in. liquid outlet line. In the example given, a leak in this 2-in. line, either at a pump or fin-fan exchanger, would result in > 700 ppmv of H2S in the immediate breathing zone, which could result in death for personnel near the leak.5 Because of the severity of a leak, an EBV may be recommended on the liquid outlet line.
Inventory levels. The next point involves the material inventory within vessels. Since API RP 553 does not specify an inventory threshold for requiring EBVs in Section 8.1.3 (Vessels), the guidelines provided in Section 8.1.2 (Pumps) may be applied by extension. Therefore, according to those guidelines, vessels containing < 2,000 gal of light ends, toxic materials or hydrocarbons above their flash point or < 4,000 gal of other hydrocarbons are not required to have an EBV.
This brings up a key distinction between normal inventory vs. maximum inventory. API RP 553 does not specify whether the total vessel volume or normal liquid inventory is the basis when determining if an EBV is needed. However, the language in bullet points 1 and 2 of the pumps section, again, may be used. The first and second bullet points in the pumps section state that EBVs are recommended when a “vessel contains more than X gallons.” Based on the use of the word “contains,” it can be inferred that normal inventory is the relevant measure. For instance, a distillation column that contains hydrocarbons above their flash point may have a shell with a total volume of 5,000 gal but has a normal liquid level such that the vessel contains only 800 gal; an EBV would not be recommended for this case.
This same principle applies to pumparounds and side strippers. Pumparounds, in the event of a seal leak or other leak at the pump, have only a small inventory of hydrocarbons that can be released. In many distillation columns, the volume of liquid hydrocarbons in the tray at and above the pumparound or side stripper draw is well under the 2,000-gal limit.
Heaters. Like the pumps section, the language in Section 8.1.3 (Heaters) is generally well defined; however, there is some ambiguity in the second bullet point, which states that “an EBV is needed for each process-side feed line to a fired heater that contains flammable fluid.” However, this may not always hold true. Based on the inventory guidelines in the pump section (then applied by extension to the vessels section), which recommend EBVs for vessels containing > 2,000 gal of light-end hydrocarbons or > 4,000 gal of other hydrocarbons, a similar approach can be applied to heaters. Specifically, heaters that are fed by vessels with hydrocarbon volumes below these thresholds would not require an EBV on the process inlet. For example, a fixed-bed platforming unit containing three reactors and three heaters in series were analyzed for a potential need of EBVs. The volume of the reactor (each located upstream of a heater) had volumes < the 2,000-gal threshold, suggesting that EBVs on the process feed lines to the heaters were not necessary in this case.
Preventive maintenance (PM). While API RP 553 does not specifically address it, insurance companies and refining clients have highlighted the importance of establishing a PM and testing schedule for EBVs. Operators must have confidence that these valves will function properly to prevent significant losses of containment. To ensure this, a consistent PM schedule should be implemented for each EBV to verify that the valves and actuators are operating effectively. Valve testing should also be a part of this PM schedule, where operators remotely actuate the EBV and verify its function. To allow for this, EBVs should be installed with bypasses and double block and bleed valves to avoid any disruption to normal operation.
Takeaways. In summary, the implementation of EBVs plays a critical role in minimizing the risk associated with hazardous material releases in refineries. As detailed in API RP 553, Section 8, these valves help prevent large-scale containment losses and fires or toxic exposures. While API RP 553 provides clear guidelines for EBV installation, there are some instances where further clarification or analysis are necessary. TABLE 1 and FIGS. 1–6 incorporate the above sections and provide a streamlined process for determining if an EBV is recommended. As mentioned, a PHA for assessing risks should be conducted prior to adding or discounting EBVs in a process unit. HP
LITERATURE CITED
U.S. CSB, “Valero McKee refinery propane fire,” July 9, 2008, online: https://www.csb.gov/valero-mckee-refinery-propane-fire/
U.S. CSB, “KMCO LLC fatal fire and explosion,” December 21, 2023, online: https://www.csb.gov/kmco-llc-fatal-fire-and-explosion-/
API, “API RP 553: Refinery valves and accessories for control and safety instrumented systems, 2nd Ed.,” October 1, 2012.
Meyers, R. A., Handbook of petroleum refining processes, McGraw-Hill, New York, New York, 1986.
Bertelsmann, A., et al., “PHA guidance for correlating H2S concentrations in process streams to severity of adverse health outcomes in the event of a leak,” Journal of Loss Prevention in the Process Industries, May 2019.
Ken McIntush, P.E., is a practicing chemical engineer and President of Trimeric Corp. He has > 30 yrs of process engineering experience, serving clients in oil refining, oil and gas processing, petrochemicals, specialty chemicals and others. McIntush has been with Trimeric for the last 22 yrs. Trimeric provides consulting and engineering to clients on topics such as the one in this article and many others. McIntush earned a BS degree in chemical engineering from Texas A&M University in College Station, Texas.
Ethan Pulfrey, E.I.T., is a practicing process engineer at Trimeric Corp. He has 4 yrs of process engineering experience, serving clients in oil refining, oil and gas processing, and petrochemical industries. Pulfrey earned a BS degree in mechanical engineering from Louisiana State University.
Rosalind Jones is a Senior Engineer at Trimeric Corp. She has > 35 yrs of process engineering experience in petrochemical, oil and gas, and other industries. She has worked extensively in process R&D, process plant design, manufacturing and process safety. She earned a BS degree in engineering science, with a chemical engineering concentration from Trinity University in San Antonio, Texas, and is a Certified Six Sigma Black Belt.
Shanahan Mondal is the Owner and Industry Advisor at Beacon Process Safety Services in Sulphur, Louisiana. He has > 27 yrs of experience in both technical and leadership roles across process engineering, advanced process control, process safety and HSE. Mondal has worked in these roles at organizations, including Solvay Polymers, Sasol, Marathon Petroleum, Valero, CVR Energy and Cheniere Energy. He has expertise in polypropylene/polyethylene production, ethylene production, coking, desulfurization and hydrotreating. Most recently, he served as Director-HSE at Cheniere Energy's Sabine Pass Liquefaction terminal. He earned a BS degree in chemical engineering from the Massachusetts Institute of Technology.