Controlling steam: What you don't know can hurt you

July 12, 2018
Why are steam systems so pervasive?

This Control Talk column appeared in the July 2018 print edition of Control. To read more Control Talk columns click here or read the Control Talk blog here

Greg: Steam is the most common method of providing heat to a process. We are fortunate to have Steve Huffman, vice president of marketing and business development for Mead O’Brien, Inc., to give us inside knowledge inside steam systems. Steve has been providing incredible support for the automation profession. He was ISA president in 2007, Chairman of the Automation Federation in 2007 and 2008, and is currently chairman of Government Relations for the Automation Federation. I have been working with Steve in the review and expansion of the Automation Competency Model (ACM). Steve, why are steam systems so pervasive?

Steve: Steam systems are the most efficient means of heat transfer in industry with more heat content per unit volume, higher temperatures available for heat transfer, and no need for pumping systems to distribute steam to its intended points of use. Unfortunately, a lot of knowledge regarding steam systems as applied to heat transfer is being lost due to experienced practitioner retirements and failure by newer engineers and technicians to understand the thermodynamic properties of steam and how they affect the system in a heat transfer control loop.

Greg: How do we get into trouble?

Steve: Too often, steam system piping designs tend to be like water or air systems without providing adequate drip legs, separators and traps to remove condensate from heat loss in the distribution piping. Designers also fail to understand that there are steam volumetric increases occurring with pressure reduction and higher pressure drops at higher flows, which will affect the amount of steam delivered. Once steam gets to the control valve, the wrong selection of inherent trim characteristic will lead to other issues when the control loop is operating at less than full-temperature-rise conditions. Since heat transfer surface area is sized for the worst condition, there is more surface area than needed for the throttling condition where less temperature rise is needed. Therefore, the normal controller output tends to be low. Selection of equal-percentage trim inherent flow characteristic helps address the problems created from operating closer to the closed position.

Greg: The open-loop gain is the product of the process gain (slope of plot of temperature vs. manipulated flow), valve gain (installed flow characteristic slope) and measurement gain (100%/span). The process gain often increases at low demand. Sizing heat transfer surfaces for maximum demand makes this increase in gain at low demand even greater. The equal-percentage trim characteristic helps in three ways: The valve gain (installed flow characteristic slope) being lower at low flows makes the product of process gain and valve gain more linear. The real rangeability is increased because the amplification of a lack of precision from backlash and stiction is decreased. Finally, the overall linearity of the installed flow characteristic is better when the valve drop to system drop ratio is small (e.g., less than 0.5). In contrast, the valve gain for linear trim is much greater at low demand, becoming quick opening for small ratios and resulting in more non-linearity in both valve and open-loop gain, and less rangeability. These considerations and much more are discussed in my 5/06/2015 Control Talk blog, “Best Control Valve Characteristic Tips.” The effect of the ratio of valve drop to system drop on the installed flow characteristic is seen on slides 34 and 35 in the ISA Mentor Program Webinar, “How to Get the Most Out of Control Valve.” This recording along with others is available on the ISA Interchange site at https://automation.isa.org/ by clicking on “Education & Training” in the heading and choosing ISA Mentor Program Webinars. Why is valve sizing so critical?

Steve: Certainly, as in any process controlled with valves, it’s up to the control valve to deliver the benefits and cumulative accuracy of the other control loop components. As the final control element, it needs to be precise (minimum backlash and stiction) and provide a linear gain (product of process gain and installed flow characteristic slope that is relatively constant). That said, the steam system has many other challenges that other process loops may not have. The valve can only work well if there is a properly operating steam trap downstream of the heat exchanger to stop the flow of steam to allow transfer of latent heat BTUs from the steam to the process, remove the resultant condensate as it forms from the heat exchanger, and remove non-condensable gases common with all steam systems. When steam condenses in a heat exchanger, the volumetric change from steam to condensate is about 1,000:1 in cu.ft./lb. depending on pressure. If the control valve is throttling down steam flow as a control response and therefore not replacing the condensed steam with an equal volume, then the system will head toward vacuum or at the very least, leave very little operating pressure for the steam traps to remove condensate, as their capacity is based on differential pressure across the trap valve orifice. If there is an overhead condensate return, the static head pressure created in the riser may cause the trap to stall and be unable to move the condensate to the overhead return. In this case, it may be necessary to add a pump, a pumping trap that can act as both a pump and/or a trap, a combination of a mechanical pump and a trap, or on/off control to maintain high volume tank temperature.

Greg: What are some of the other problems caused by condensate accumulation?

Steve: In the steam distribution system, do not fail to include drip legs, separators and drip steam traps to eliminate accumulating condensate that can cause differential shock water hammer. If there is considerable unremoved condensate sharing the distribution pipe, steam traveling at a much higher velocity than the slow-moving condensate will create a wave action and the probability of a dangerous slug from a condensate wave bridging the internal diameter of the pipe. The slug will accumulate more condensate as it travels at the steam velocity. As soon as the slug encounters equipment or a change of direction, such as valves, tees or elbows, serious damage may occur. If sub-cooled condensate exists due to stall or in a heat exchanger that is not drained by gravity to the steam trap between batches, sudden volumetric implosion of condensing steam into cold condensate may cause violent thermal shock and may create a void that is violently filled by the cold condensate, which may impinge off itself to form shock waves and likely damage equipment.

Greg: What about the effect of gases and solids in steam?

Steve: Any type of non-condensable gas acts as an insulator to heat transfer surfaces, greatly reducing the thermal efficiency. Carbon dioxide will go into solution in cooled condensate, which creates very corrosive carbonic acid (H2CO3). Piping that has corroded from the inside out likely has carbonic acid issues, likely from not draining condensate. Oxygen speeds up pitting corrosion from oxidation, again by going into solution in cooled condensate. Particles (e.g., dirt and scale carryover from a boiler) can cause fouling, reducing the heat transfer coefficient, and can interfere with the operation of some steam traps types not able to handle dirt well.

Greg: What do we need to know about steam traps?

Steve: As I mentioned, steam traps must, at a minimum, do three things: Stop the flow of steam into the condensate system; remove condensate, preferably as it is formed when used in process duty; and remove non-condensable gases. The trap should be mounted at least 12 in. below the heat exchanger as general practice to allow for the gravity flow of condensate from the heat exchanger. Since we are stopping the flow of steam to maintain pressure and saturated temperature in order to transfer latent heat, pressure does not get condensate to the trap. Frequently, packaged equipment skids, particularly those including plate and frame (P&F) heat exchangers, do not address the issue of gravity flow to the steam trap. Since P&F condensate connections are horizontal and low on the connection frame, the skid manufacturer does not allow the 12 in. necessary to fully remove the condensate from the bottom of the plates, which can result in thermal shock and a lot of gasket replacements. Trap sizing and selection is critical. Both inverted bucket (IB) and float & thermostatic (F&T) traps are widely used for process service, primarily because they are able to remove condensate as it forms, which is a reason for their larger physical size. Other attributes should be considered, such as failure position, ability to allow continuous flow of condensate from the heat exchanger without backing up condensate, ability to handle dirt, higher end capacity, ability to operate on low differential, air removal capability and service life, to name a few.

Greg: Can the right steam trap design and installation solve all problems with condensate removal?

Steve: I would say that the right steam trap design and installation is critical to efficient condensate removal, but it doesn’t solve all potential problems. It’s true that one of the three primary functions of the steam trap is to remove non-condensable gases. However, many plants save installation cost with modularization of steam supply and condensate removal equipment at some distance and/or height away from process heat exchangers such as brew kettles in breweries, cookers or process heaters in batch process plants, steam coils in large ducts or plenums, etc., sometimes due to floor space restrictions, size or configuration. This issue, frequently combined with larger internal areas of heat transfer equipment, makes it imperative that supplemental devices be used to remove these gases as quickly and as close as possible to the area where they would be entrapped: opposite the steam supply connection of the exchanger.

Greg: What are the supplemental devices, and how do we use them?

Steve: The supplemental devices are vacuum breakers (VB) and thermostatic air vents (TAV).

VB are spring-loaded valve and seat devices mounted on or near the steam space of a heat exchanger allowing steam pressurization of the space, but during throttling down or shut-off of steam supply, also allow the valve to overcome the spring force and open when vacuum is present. The vacuum is formed when steam, with its much higher specific volume than water, condenses to water with heat exchange and is not replaced in the heat exchange space with an equivalent volume of steam, i.e., when the control valve is throttling down from its process design maximum flow, or when steam is being shut off after completion of the process step. “Breaking” the sub-atmospheric condition that occurs in those situations by allowing air into what was the steam space enables condensate drainage from the heat exchanger by gravity. This prevents water hammer, internal corrosion, gasket or joint leakage, and potential damage to the heat exchanger and other equipment. Without this device, a reverse pressure differential is formed in the steam space due to vacuum, which will suck available condensate from the return system into the calandria, coil or other large-cavity heat exchanger.

TAV are also valve-and-seat devices that are actuated by temperature, typically a “balanced” bellows. The bellows has an alcohol and water charge inside that evaporates and expands on temperature increase, approaching the steam saturation curve for the particular steam pressure. The expanding bellows drives the valve into the seat and closes the device. On steam start-up of the heat exchanger, cool air is expelled quickly through this device until steam reaches it, which quickly closes the valve. Similarly, on decreasing temperature, at some point a few degrees lower than the steam saturation curve, the mixture in the bellows condenses and contracts the bellows, which pulls the valve plug away from the seat and thus opens the vent. This signifies that non-condensable gases have accumulated and the temperature has depressed enough to allow the valve to open and expel them from the steam space. Pressure is inconsequential up to the TAV design pressure since the alcohol charge is designed to follow the steam saturation curve—offset but parallel, always activating a few degrees below saturation temperature for any given pressure (including vacuum).

Greg: What do we need to know about their installation?

Steve: Their mounting is critical to their successful operation. Observe the following rules for mounting:

  • As close to the exchanger as possible on a line with a vertical accumulator, if not on the exchanger itself, opposite the steam supply.
  • Condensate line must be large enough to allow disengagement if horizontal or a vertical accumulator will be needed. If not, the TAV will discharge condensate, which means it is not discharging air. The vacuum breaker will spit and leak over time as well.
  • The vertical accumulator is used to provide an accumulation area for non-condensables. It is typically 2-in. or larger pipe, approximately 2 ft. high if space allows. An isolation valve should be used between the accumulator and the TAV to isolate for maintenance or system air testing. Note that these devices should be excluded from any air test boundaries since the bellows is “balanced,” meaning that steam pressure has a corresponding saturation temperature to “balance” internal pressure of the bellows against external pressure caused by the steam pressure. Air would not allow this balance to take place and would either not close the valve on the air test, or would rupture the bellows if the isolation valve were downstream.

Since mounting preferences are similar for both vacuum breakers and air vents, a new device has been developed that accomplishes both functions in one device. This is the TAVB-3, which has become standard at a large brewing company.

Greg: For more on steam trap design, installation and capability see the Armstrong Steam Conversation Guidelines for Condensate Drainage.

Top 10 ways to improve steam systems

10. Ensure that the steam boiler is sized large enough to meet the current system consumption and possible future expansion. Remember: BTUs are needed to get feedwater to saturation temperature, and heat loss in piping due to insulation inefficiency.

9. Size steam distribution piping for 6,000 FPM velocity below 50 psig steam pressure, and 8,000 FPM velocity for 50 psig and above. Remember: Lower steam pressure has higher specific volume than higher pressure.

8. Make sure drip legs with drip steam traps are used to remove condensate from steam distribution lines to prevent thermal shock water hammer and poor-quality steam delivered to the heat exchanger. Remember: Drip legs should be about 2 ft. long and the same size as the steam pipe up to 4 in., and half the size of the pipe above 4 in.

7. Use equal-percentage inherent trim characteristic control valves for process temperature control on steam, sized to operate between 20% and 80% open, min to max. Remember: Non-linearity in the form of high gain under partial steam load conditions is plotted as the inverse of the equal-percentage curve to become close to linear in the installed trim characteristic applied to the process.

6. Use supplemental thermostatic air vents and vacuum breakers (or a single device that does both) on large-cavity heat exchangers. Remember: Air is an insulator and is detrimental to surface temperature, and vacuum, formed by steam condensing and not replaced with an equivalent volume of steam, prevents the gravity flow of condensate from the exchanger to a steam trap, allowing potential thermal shock, water hammer and/or internal corrosion.

5. Select the proper steam trap for the application. On modulated steam applications, float and thermostatic (F&T) steam traps and inverted bucket steam traps are both acceptable depending on performance characteristics desired. Remember: Steam traps must 1) stop the flow of steam to allow desired steam pressure to be maintained on the heat exchanger while latent heat is transferred to the process, 2) remove condensate in the heat exchanger simultaneously, and 3) remove non-condensable gases.

4. Ensure the steam trap can provide the capacity at low differential and can overcome static head pressure created by an overhead condensate return. Remember: If that condition can occur, use a mechanical (steam-powered) pump as a closed system in combination with an F&T trap, a double-duty-type combination device, or a separate, open system pump/receiver, either mechanical or electric.

3. When the system is operating smoothly and efficiently, look for more ways to increase efficiency by auditing different areas of the generation, distribution, heat transfer and condensate-handling systems periodically, and look for opportunities to design and use heat recovery systems. At a minimum, test steam traps once a year for proper operation, but to eliminate the plus-or-minus six months of lag time between discovery of failed traps at that one moment in time, plus the time it takes to arrange and actually repair or replace the steam trap, consider a wireless steam trap monitoring system, at least for the most process-important or highest pressure steam traps that will have the largest steam loss. Discovery of failure is within minutes, the system can self-generate a work order, and the repair can be done quickly. One such system uses either ISA100 or WirelessHART mesh networks reporting to a measurement, monitoring and reporting software system designed to manage the system effectively.

2. If you don’t really understand the thermodynamics, proper piping techniques, and potential problems that may occur in your steam system, don’t experiment. Contact someone who has thorough knowledge of steam systems before making that first change.

1. If you understand your steam heat transfer system, have never instructed someone to “just change out the steam trap, it must be to blame for my system not working correctly, since I don’t really know what it does,” then you may be numbered in that new group: “Steam system practitioner, the making of a new kind of Prima Donna.”

About the author: Greg McMillan
About the Author

Greg McMillan | Columnist

Greg K. McMillan captures the wisdom of talented leaders in process control and adds his perspective based on more than 50 years of experience, cartoons by Ted Williams and Top 10 lists.