Safety instrumented systems: Applying measurement best practices

The measurement part of a safety system tends to be the most troublesome. However, new technologies offer ways to overcome many common-cause problems.

02/13/2017


Figure 1: Heat dissipation can occur very rapidly as ambient temperatures drop, even over seemingly short sensing line lengths. Courtesy: Emerson Automation SolutionsDesigners and operators of safety instrumented systems (SIS) in hydrocarbon processing industries can benefit from a variety of new technologies related to design, diversity, and diagnostics. Products and application best practices have worked together to make an SIS and individual safety instrumented functions (SIFs) work more effectively, and as a result, can eliminate many common-cause problems that can interfere with safety loop performance.

Most of these problems are related to the measurement side of the equation, when a variety of sensing technologies are used. This article considers several examples related to pressure and level in applications common in hydrocarbon processing and other industries. The elements of design, diversity, and diagnostics don't apply to every example, but one or more will be applicable in each case. 

Dealing with common-cause problems

Best practice design concepts for an SIS have evolved over the past decade, prompted by widespread adoption of the ANSI/ISA-S84.01-2004 and IEC 61511 standards. Calculation methods for quantifying risk are well understood, but for measurements, the key challenge is finding relevant data related to instrument performance. While suppliers often provide safety statistics they claim are certified by third parties, the data typically are derived from white papers or laboratory analysis and apply to the device itself in isolation, installed in laboratory conditions.

Unfortunately, in real hydrocarbon processing environments, the risk of a transmitter not responding properly to an incident, thereby falsely reporting safe conditions, can be significantly higher for a variety of real-world interface risks such as:

  • Pressure instrument impulse line plugging or freezing
  • Slow sensor or capillary response as a result of cold temperatures
  • Temperature sensor coating
  • Erosion or coating of primary flow element
  • Process fluid density change in level measurement.

In cases where one or more of these risk conditions affects more than one transmitter—creating a common cause—it will dominate overall system risk in a typical redundant installation. Unfortunately, this is often the case, because the root cause of the risk usually is a characteristic of the process itself. For example, the root cause of line plugging usually is dirty process fluid, which, of course, will be in contact with and affect all transmitters connected to the specific process.

For example, suppose the risk of a dangerous pressure transmitter failure-meaning it reports the process pressure is in a safe range when it is actually past a safety limit-is 0.01 failures per year. So, if 100 devices are installed in the same application, one device could experience such a dangerous failure each year. Extending the example, suppose the risk of the impulse lines connecting the transmitter to the process will plug is 0.005 failures per year. We can assume that if the impulse lines connecting one transmitter become plugged, the line(s) connecting the other(s) probably eventually will become plugged as well because they are exposed to the same environment. That makes this is a common-cause risk.

Risk with a single transmitter = λTransmitter + λPlugging = (0.01)1 + 0.005 = 0.0150

Risk with two transmitters = (λTransmitter)2 + λPlugging = (0.01)2 + 0.005 = 0.0051

Risk with three transmitters = (λTransmitter)3 + λPlugging = (0.01)3 + 0.005 = 0.0050

This simplified calculation shows how when the transmitters are redundant, any common cause will dominate safety risk for the measurement. Therefore, adding more transmitters subject to the same common cause provides minimal safety risk reduction. Trying to quantify the risk of a real-world common cause-related failure with any degree of precision-especially in a new application-is difficult. Consequently, an engineer should aim to minimize each common-cause risk by using best practices for design, technology, diversity, and diagnostics available with smart transmitters. 

Improving pressure measurements: Design and diagnostics

In general, safety engineers should use the same design best practices in safety applications as those proven effective in basic process control applications. Of course, best practices evolve over time as users and suppliers gain greater familiarity with new technologies, accommodating their strengths and weaknesses.

The table lists common capillary fill fluids and compares their boiling points at atmospheric pressure and viscosities in centistokes (cSt) at selected temperatures. Source: Rosemount with data from Dow Corning

As previously mentioned, pressure transmitters usually are connected to the process using sensing or impulse lines. These lines make it possible to locate the transmitter remotely from the process connection, where it may be better protected or accessed more easily for maintenance. Where differential pressure (DP) is measured (for example, to obtain level in a closed vessel or pressure drop across a flow element or a filter), sensing lines allow the transmitter to be installed between the two taps. Sensing lines filled with process liquid are called "wet legs." However, they are called "dry legs" if filled with process vapor. Most users find both require frequent maintenance because fluids in wet legs tend to evaporate or become contaminated, and process vapors in dry legs tend to condense. For these and other reasons, many users replace wet or dry legs with oil-filled seals and filled capillary tubes.

 

Figure 2: Thermally-optimized seal systems can provide fast responses with a hot process in a cold environment, even without external heating. Courtesy: Emerson Automation SolutionsIf the process and environment are at different temperatures, the temperature along the sensing line will change as heat is transferred to or from the environment. This complicates design when the process is consistently hot but the ambient temperature varies, as is common in outdoor installations. If the line is short, insufficient heat will be dissipated in summer, possibly allowing the transmitter to become overheated and damaged. This is usually an overt failure, making it easy to spot, but the transmitter will need to be replaced. On the other hand, if the line is long, too much heat may be dissipated in winter. Figure 1 shows how a typical sensing line can cool by 140°C in 160 mm (6 inches) when the ambient temperature is 0°C.

As the temperature falls, the process fluid or capillary fill fluid may begin to thicken, crystallize, or separate before it reaches the transmitter. Lowering the temperature increases the viscosity of various capillary fill fluids, just as it does with typical process fluids in hydrocarbon processing industries (see Table). In general, boiling point rises along with molecular weight and so does viscosity.

Raising viscosity in a sensing line or capillary beyond an acceptable limit slows the sensor's response to changing pressure. A 5-m capillary tube with a 10-mm internal diameter filled with a less-than 5 centistokes (cSt) fluid will dampen response time by 1 to 2 seconds. If the fluid viscosity increases to more than 150 cSt, the same system will see response time increase by more than 30 seconds. Of course, a system with solid-fill fluid will provide no response at all, but this may not be obvious because even a plugged system can retain its previous pressure.

Even where redundant transmitters have physically different connections to the process, the lines often will have similar length and be filled with the same fluid. For this reason, all connected transmitters typically suffer the same slow response or possibly no response. When this happens, if process pressure changes quickly, the value measured by the impaired device may be significantly different from the process pressure, but the logic solver will not detect any deviation between the transmitters. In this example, if a pressure excursion can cause a safety risk within 30 seconds-which is often true-the safety system will not initiate a shutdown in time and a safety incident could follow.

Even with insulation, heat dissipation in outdoor applications can be five to 10 times faster in winter than summer. For this reason, it is usually not possible to design a single set of sensing lines that can avoid overheating in summer and overcooling in winter. This leaves many users installing thermostatically-controlled heat tracing, as shown on the upper right in Figure 2, on sensing lines and capillaries to maintain optimum temperatures. But this adds significant upfront and ongoing maintenance costs. 


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