Safety Instrumented Systems (SIS) provide a critical layer of protection for process facilities, which can be dangerous places because of the chemicals and processes involved. There are two main standards that exist to define the design and implementation of safety systems: IEC 61508 and IEC 61511. IEC 61508 addresses the manufacturers and suppliers of devices for safety systems while IEC 61511 is intended for the safety instrument systems designers, integrators and users.
Before getting into how valve selection is affected, let’s first go through the basics of SIS design. This all starts with a risk study and HAZOP analysis to determine what safety integrity level (SIL) is required for the loop, i.e. SIL 1, 2 or 3. The ideal objective would be to engineer as much risk as possible out of the system at this point. This is not only to have a safer system but to reduce the future requirements for testing and maintenance.
Several other factors are considered in the overall system design including performance needs, testing procedures and lifecycle requirements, and environmental requirements such as fugitive emissions or reducing/eliminating flares. Also consider what technology will be utilized, from the logic solver to the final control element (valve) and contract management, considering budgets, suppliers and schedule needs.
In refineries, safety systems will be found in nearly every process unit, including hydrotreating, hydrocracking, vacuum and crude distillation, and coker and desulfurization units. Nearly all safety instrumented functions require SIL 1 or SIL 2. There are several common applications for SIS in refining, including burner management systems for furnaces, applications within catalytic crackers, fire and gas monitoring and protection, emergency blow-down valves and excess-heat-relief valves. Analyzing a refinery in the Middle East, here is the breakout of the frequency of different SIL requirements across the safety instrumented functions:
With multiple safety applications throughout a refinery, the valve challenges will certainly vary but there are a few overarching challenges. To start, it’s important to remember the basics of valve selection and ensure the right valve is chosen for the application. For example, one could select a globe valve, spring and diaphragm actuator and positioner, review the safety certifications from the manufacturer for each product and conduct the safety calculations that show everything is okay. But, if that globe valve is being put into a slurry service, then it’s probably not the best choice due to plugging and/or erosion concerns. It’s important, as with any valve selection, to consider the valve type, materials and fluid challenges in addition to the product safety certification. The failure rates given from the certifying body often assume clean service. The safety instrumented system designer will use his or her discretion to select the most appropriate valve configuration.
Once the appropriate valve assembly is selected and it comes time to order the equipment, there is often a different supplier for each component. Also, a system integrator is frequently used to put it all together. This could introduce the possibility for error when selecting all the right components and ensuring they work as needed together. Since these can be highly engineered solutions, it may be wise to go to one vendor who can do all of this to reduce risk.
The Bottom Line: Is My Valve Going to Move When I Need It To?
Equipment is subject to basic wear and tear over time, especially the final control element, as it is exposed to the process. As such, the SIL capability will deteriorate over time. There are different ways to maintain the SIL level over time, but it is primarily done through testing. The most conventional way to test a valve is to take the valve offline and perform a full stroke valve test, known as a proof test.
Proof tests are required to maintain SIL level, especially for extended maintenance intervals. This can be a challenge if your maintenance interval is longer than your time required between proof tests. This may be because the unit uptime between turnarounds is being extended.
Partial stroke tests can be used to extend the time between full proof tests. Some refiners have adopted partial stroke testing for many of their safety valves, some leverage it for valves that do not have bypasses, and others currently don’t use this at all. A partial stroke test can identify many failure modes, but it cannot identify everything that a full stroke proof test would capture.
Table 1. Failures Identified by Partial Stroke and Full Stroke Testing1. Items in bold are identified by utilizing a smart positioner.
There are different ways to conduct partial stroke testing: primarily visual testing or with valve positioner diagnostics. A Middle East refinery had a 24-inch ball valve—critical for safety shutdown—on which regular checks were conducted. The operators ensured the valve was moving by watching the outboard shaft of this rotary valve. These checks showed it was working fine until they were surprised by an incident that occurred with the valve. Unfortunately, those performing the testing were only witnessing the movement of the outboard shaft and the actual plug/shaft connection was broken. The refinery added a digital valve positioner to the valve to use the positioner diagnostics for analyzing shaft integrity. In the future, if a low torque alert came up during partial stroke testing, site personnel knew to question the shaft integrity.
One fear with partial stroke testing is that the system and valve positioner will keep trying to make the valve move, even if there’s a blockage. It might jump open and cause a process upset or safety issue. This can be avoided with technology available in some valve positioners. Figure 2 below shows a partial stroke test from a Gulf Coast refinery where the test was aborted by the valve positioner after the pressure dropped below a configured minimum. The pressure output was then returned to normal and a “Valve Stuck” alert was issued.
Another benefit of digital valve positioners is they can be used to record demand scenarios. For example, a Texas refinery experienced a demand while shutting down process units in advance of the approaching Hurricane Rita. The positioner recorded the demand and reset stroke, which counted as full proof tests. Without these records, proof tests would have added multiple days to the start-up schedule after the hurricane, incurring significant production impacts costing upwards of $2 million per day. While some refineries may choose not to leverage this demand scenario as a full proof test, many will still look at any diagnostics captured and incorporate any findings into their predictive maintenance planning.
When considering valve applications for SIS, it’s important to remember the basics and to review the application needs to ensure the valve is appropriate for all the application requirements, not just SIL capability. It might be worth consideration to consolidate to one vendor for SIS valve solutions. If that’s not the right path for your refinery, ensure you have good communication between your vendors to get well-engineered solutions.
Most of all, review how you’re testing your valves. Often, each company has its own philosophy with regards to testing and equipment utilized, and this is determined by multiple departments such as engineering, safety and operations. If it’s a visual exam, is it telling you everything that you need to know? If not, it could be appropriate to add a smart positioner. If you already have a smart positioner, be sure to fully leverage its diagnostic capabilities.
- “Partial Stroke Testing of Block Valves,” Instrument Engineers Handbook, Volume 4, 2006.