Valves Forum - Recent Threads

DVC6200 didn't response to DeltaV input

Daniel Lou — Fri, 30 Jan 2026 03:03:36 GMT

DVC6200 is used in DeltaV and AMS environmen. Now in DeltaV control studio shows that AO module out and BKCAL_OUT were in red with cross mark. It stopped to response DCS input. DVC6200 could be open in AMS and ValveLink Snap on. We found there is no any alert and is in "In Service" mode. In DeltaV diagnostic, OInteg is BAD, Status is “Configuration Scale Does Not Match Device”. We checked input range at device is 0%-100% which is same as AO module setting.

After change mode from In service to out of service and back to in service, this issue is resolved.

What is the reason and what should I do to prevent this happen again. Thanks

Daniel

Intrepretation of a brand new butterfly valve signature from Valvelink

Shaiq Bashir — Wed, 04 Sep 2024 16:12:42 GMT

Dear All

We have a brand new butterfly valve with fisher DVC6200 PD positioner. Attached is the signature we have taken from Valvelink for this valve assembly. Can you please help me interpret it as it does not look normal.

Secondly, the blue line represents the signal from close to open or open to close?

Regards

Is there also any Multi-Stage Pressure Drop effect on Fisher Whisper Trim III (for Gas Application)?,

Faiz Faiz — Tue, 11 Jun 2024 04:24:22 GMT

Dear Experts,

I need control valve for gas application (specifically for Compressor Recycle), dropping pressure from 670 psig to 200 psig. As per sizing result from manufacture, we got the recommendation to use Whisper Trim III. Question:

Is there also any multi-stage pressure drop effect on Whisper Trim III?, similar like Cavitrol III for liquid application.
To minimize liquid formed during pressure dropping from 670 psig to 200 psig

Thank you in advance,

Faiz

Difference between ED, ET, ES and EZ

Gerard Nagle — Mon, 09 Oct 2023 07:32:04 GMT

Hi there,

To me, the ED and ET are very similar e-body valves, with the only difference I can see is that the ET has a soft seat option as standard, but even then, the ED has up to class V as option.

Also, both the ES and EZ are unbalanced types, so quite similar.

I've looked around, and can't seem to see any guideline on why you would select an Ed over and Et, and the same, why an ES over an EZ.

Any input on why or a link to a document on why, would be great.

thanks

Gerard

FCI 70-2 pressure testing standard query

Shaiq Bashir — Mon, 13 Mar 2023 20:36:52 GMT

I understand that Fisher uses FCI 70-2 standard for control valve leakage test. Can someone kindly explain that why for Class VI valves the FCI asks for test pressure of only 50 psig? Is there any impact on valve if this test pressure is increased?

Regards

Article: Rethink Your Control Valve Servicing

MarcyStevenson — Wed, 07 Sep 2022 21:38:35 GMT

Reduce Turnaround Time and Effort

Emerson Automation Solutions Senior Engineers Scott Grunwald and Karl Lanes recently published an article in the September 2022 issue of Chemical Processing. It is titled “Rethink Your Control Valve Servicing,” and it describes techniques to better focus shutdown efforts and reduce costs. A summary of the article follows.

Shutdowns, turnarounds and outages (STOs) are a stressful time for plant personnel. Production is stopped and every minute costs the company thousands of dollars. This article examines the STO process from pre-planning through execution, providing methods to save time and reduce costs.

STO chaos
During a typical STO, operations staff balloons to hundreds of workers, and all are competing for personnel and equipment resources. Maintenance departments usually takes the opportunity to pull and repair hundreds of valves. Invariably, unexpected damage is found, creating unplanned surprises, extending the STO, and exceeding the budget.

Ways to address the problem
Historically there have been a couple of theories of valve repair:

Run valves to failure
Overhaul every valve during every STO.
Repair by replacement, where valves are proactively replaced based on their age, service, etc.

Option 1 is cheap in the short term but invariably cost much more in the long term. Option 2 dramatically reduces unplanned surprises, but it comes at a very high price. Option 3 requires a lot of guesswork because valves tend to unexpectedly fail.

But there is a fourth option, as the authors explain:

Another method of tackling the STO problem is to only pull and overhaul the control valves that require service. Many valves operate in relatively benign conditions and can go years without any maintenance at all, so there is no reason to needlessly pull them. Of course, the challenge to this method is knowing which valves have problems and which do not.

This method has proven to save significant STO costs, but it requires the plant to predict when valves need attention. The plant needs to know:

What control valves are installed, including sub-components.
A history of how the valve has been operating to date.
An indication of how the valve is performing now.

Armed with that information, it is straightforward to assess which valves should be overhauled now and which repairs can be deferred. Even using this procedure, there is always a risk that a valve could unexpectedly fail, so certain critical and severe service valves are typically pulled during every shutdown.

STO execution
If the data is available, the control valve STO becomes a much more manageable exercise, as shown in Figure 1.

Figure 1: If the right information is available, control valve STO efforts are much less onerous. Data is used to create the list of valves that require repair, and pre-planning ensures the necessary parts and resources are available.

Ideally the health of each valve is evaluated using data and equipment inspections to create a list of valves to overhaul. Critical valves are added to the list. Then the list is re-evaluated to determine what equipment upgrades might be best incorporated during the repair.

With the STO scope defined, the team plans the logistics of the event, orders the parts, and works out repair details. A carefully planned STO becomes much less challenging, with cost and schedule overruns reduced or eliminated. While this alternative method has many benefits, it is ultimately predicated on complete information on the valves. But what does a plant do if it lacks that data?

Gathering field data and reducing emissions
If valve information is unavailable, many plants start by walking down each valve and gathering information. Many plants also use this walkdown as an opportunity to address fugitive emissions by specifically targeting valves handling volatile organic materials and/or restricted materials. The authors explain:

Leakage results in lost product, generates increased testing requirements under the Environmental Protection Agency’s Leak Detection and Repair program, and can ultimately generate fines. The findings of the environmental walkdown can be used to generate a target list of valves for repair and/or improvements during the STO.

Diagnostic performance data
Actual valve performance data may be available from existing digital positioners already installed on the valves. These positioners can gather performance data, flag developing problems, and transmit the information to an asset management software package. There it can be alarmed, and then internally handled, or externally reviewed by Emerson’s automation experts, who can highlight developing problems in periodic reports sent to plant staff (Figure 2).

Figure 2: Valve diagnostic data from operating valves can be captured and monitored by third-party experts. Serious issues are immediately addressed, while slowly developing problems are captured in monthly reports.

Walk downs, repair histories, and valve diagnostic data are all used to help guide the STO planning process. When evaluating repair versus upgrade versus replace options, consult with your valve vendor and lean on their expertise as they can usually provide a list of alternatives, and provide cost comparisons to determine the best solution.

Planning the repair logistics
The authors also mentioned one remaining STO planning step:

The last critical step prior before starting an STO is formulating a detailed plan for executing the repairs. The sheer logistics of pulling hundreds of control valves, overhauling them, re-installing them, and returning them to service is not to be taken lightly.

Most facilities lack the staff to handle this effort, so contracting with a valve repair company for STOs is common. The firms should be chosen carefully since some lack the technical training to perform the repairs, and others are prone to use non-OEM repair parts to cut corners. Many plants complete the repair by obtaining an “as left” stroke signature that can be compared against future performance (Figure 3).

Figure 3: During commissioning, it is important to capture a post-repair control valve stroke signature. This data can be used to spot developing problems in advance of the next plant outage.

STO savings
These techniques for pre-planning and executing plant outages have generated substantial savings:

After a failed STO, a facility utilized these techniques to better plan and focus the next STO, finishing 46% ($485,000) under budget.
A combined-cycle power plant used upgraded digital valve positioners and diagnostic alert software to focus their outage efforts and saved $68,000 in one outage alone.
Similar programs in other plants have generated average savings of $1200 per valve.

All figures courtesy of Emerson

About the Authors

Scott Grunwald is a director of global business development at Emerson Automation Solutions in Marshalltown, Iowa, where he’s responsible for shutdown, turnarounds, and outages for Emerson’s final control products.

Karl Lanes is senior director of lifecycle services at Emerson Automation Solutions in Marshalltown, Iowa, where he’s responsible for global parts distribution for Emerson’s final control products.

Article: New Technologies Solve Severe Cavitation Problems

MarcyStevenson — Mon, 15 Aug 2022 18:27:45 GMT

Cancel Cavitation

Mark Nord, Control Valve Solution Architect for Emerson and Steve Zinda, Key Account Manager at Novaspect, recently published an article in the Summer 2022 issue of Valve. It is titled “New Technologies Solve Severe Cavitation Problems,” and it describes how an advanced anti-cavitation control valve design enabled by 3D metal printing solved a power plant’s severe cavitation issue and improved their bottom line. A summary of the article follows.

Applications with very high pressure drops often create control valve problems, requiring innovative valve designs and advanced metallurgy. These issues are even more pronounced in a power plant where magnetite (iron oxide) is often present in the boiler feedwater (BFW). Valves in these applications face cavitation damage, as well as erosion and plugging caused by the magnetite.

The BFW pump (Figure 1) supplies high pressure water to the boiler. Due to the high temperatures and head pressures of the pump, a certain amount of water flow must continuously pass through the pump to avoid damage. During startup conditions, the boiler flow requirements are very low, so a boiler feedwater recirculation valve dumps water back to the separator to maintain pump throughput.

Figure 1: A boiler feedwater recirculation valve is installed on the discharge of the boiler feedwater pump, and it opens during plant startup to maintain pump flow.

The recirculation valve is a very difficult application, often taking a 2500 PSI drop when media is flowing, and it must then seal completely once the boiler water flow is adequate.

Anti-cavitation trim to the rescue?
For this type of service, valve internals typically employ an anti-cavitation trim with many tiny holes (Figure 2 – left). The series of holes limits valve damage by minimizing bubble formation in the trim, and it channels the collapsing bubbles to the center of the flow stream where they can do the least damage.

Figure 2: A typical anti-cavitation design (left) employs a number of small holes in the trim to take the pressure drop in small steps. However, in this application magnetite was plugging the holes (right), reducing capacity.

In normal applications, this works well, but in BFW applications, the magnetite tends to plate out in the trim and plug the holes (Figure 2 right). The authors describe the problem.

While cavitating conditions tend to damage valve internals, the problem is made much worse by magnetite in the feedwater, which further erodes the valve internals, and plugs the small passages inside a typical drilled hole or torturous path anti-cavitation valve trim.

As the holes plug, the flow capacity of the valve is reduced, risking damage to the high-pressure pump during low flow conditions. Particulate erosion also damages the seat, and once it is damaged, it will start leaking, which damages the seat still more. Leaking water also wastes energy and robs the boiler of water flow, reducing plant output.

The plant tried installing mesh strainers upstream of the valve, but these plugged and had to be pulled and cleaned regularly, creating a maintenance problem. Clearly, a better solution was needed.

Innovative design enabled by 3D printing
After evaluating the process conditions, Emerson engineers recommended a recently introduced anti-cavitation control valve design called Fisher dirty service trim (DST). Unlike the standard anti-cavitation trim (Figure 3 – left), the Fisher DST trim (Figure 3 – right) can pass entrained particulates up to ¾” in size. The new design also protects the seat from the major flow path, reducing erosion and ensuring tight shut off.

Figure 3: CAV III Anti-cavitation trim (left) has a large number of very small holes. The Fisher Dirty Service Trim (right) has much larger flow paths, allowing up to ¾” particulates to pass through.

The DST design was made possible by utilizing a new method of manufacturing called 3D metal printing. Lasers fuse metal powders into shapes that could not be economically produced using standard machining methods. Mark and Steve describe the process:

Historically very intricate parts could not be made of high-hardness materials because they were too brittle. However, 3D metal printing allows parts to be created from very high-grade, high-hardness materials, regardless of the level of intricacy.

In this case, the new DST valve was manufactured using R31233 cobalt chrome, so the new internals were much harder and erosion resistant than the valve trim originally installed.

Remarkable results
The new valve was installed and immediately generated significant savings for the plant. The DST trim eliminated the leakage and erosion issues, generating the following financial benefits:

Savings of $20,000 per year in reduced backpressure regulator repairs
Elimination of $100,000 per year in control valve/piping repairs
Reduced BFW pump energy costs
Extended BFW pump overhaul intervals
Increased plant capacity, generating an additional $7,000,000 per year in revenue.

Needless to say, plant personnel were pleased with the result, as was company management.

Figures all courtesy of Emerson

About the Author

Mark Nord is a Control Valve Solution Architect, Global Industry Sales at Emerson’s Flow Controls Business Unit. He has a BS in Mechanical Engineering from the University of North Dakota, and over 30 years of power industry experience, including over 25 years of control valve experience across all major industries

Steve Zinda is a Key Account Manager for Novaspect, an Emerson Impact Partner. He has a BS Mechanical Engineering and an MBA, both from UW-Madison. Zinda has 30 years of power industry experience, and he has 20 years of experience providing Emerson solutions to improve plant performance and reliability.

Article: Dangers Posed by Non-OEM Parts

mark.nymeyer — Mon, 01 Aug 2022 13:09:57 GMT

Bob Boyle, Emerson’s Vice President of the Fisher Parts Business Unit, recently published an article in the June 2022 issue of Hydrocarbon Processing. It is titled “Business Trends: Non-OEM parts—Buyer beware” and it describes how non-OEM parts are posing an escalating risk to the industrial sector, yet becoming increasingly difficult to detect. A summary of the article follows.

The world is awash in fake goods. Knock-off Rolex watches, faux name brand jeans, and counterfeit athletic shoes litter the market. What is the harm? They look real and certainly cost a lot less.

What about fake air-bags on your car, or perhaps counterfeit brake pads? Is it ok for airlines to use knock off parts for their repairs? Or consider even more frightening scenarios posed by the author:

Imagine non-OEM valve body components in 1500# service, as isolation valves for natural gas service, and even in a nuclear power plant. Each of these situations has the potential to create catastrophic damage.

Unfortunately, all the scenarios mentioned above have happened. Twenty percent of car accidents result from substandard auto parts in some markets, and in northern Europe an airliner crashed due to non-OEM engine bolts. The problem continues to escalate as non-OEM valve and valve components invade every industrial sector.

The struggle is real
Spotting fake parts used to be easy. The spelling was wrong, the equipment was poorly packaged, the part looked decidedly sub-standard, and the price was too good to be true. Those tell-tale signs are no longer common, and the fakes are getting much more difficult to identify (Figure 1).

Figure 1: The non-OEM gas valve on the left will not close properly. Other than some markings and a few very minor dimensional variations, the part looks very similar to the authentic valve on the right. (Reprinted from Department of Energy’s Counterfeit Training Manual.)

Non-OEM parts are now shipped in authentic packaging with accurate equipment labels, and they are priced at reasonable but attractive prices. Some plants pay nearly full price for a non-OEM part, never realizing it is not genuine

What is the difference?
Non-OEM valve parts can look identical to their OEM counterparts with the color, dimensions, and labeling appearing to be exactly the same. Some are openly marketed as a “direct replacement” for the original component, while others claim to actually be an OEM part. What is the difference between an OEM and a non-OEM part?

A parts replicator typically starts with an OEM part, which is often used, measures its dimensions, and uses a positive material identification (PMI) gun to identify the alloy of construction. Based on those measurements, they create the part, paint it the proper color, affix an official label, and often package and market it as the real thing.

The part may look identical but there are significant differences. The dimensions usually fall outside the allowable tolerances (Figure 2) and the fabricator has no way to determine subtle, but often critical, material differences like surface finish, hardening techniques, or specific coatings.

Figure 2: The OEM part (left) is fabricated to a design dimension and falls within an allowable tolerance band. The non-OEM part (right) is based on a single dimension taken from a used part. The resulting dimensions will often fall outside the allowable OEM tolerance band.

Figure 3 shows a wide variety of additional areas where a non-OEM part tends to fall short. Ultimately the knock off component either fails outright when placed into service, or it wears quickly, requiring replacement well before its expected end of life.

Figure 3: A PMI gun reading can indicate the specific material of construction, but it cannot determine the host of other critical material specifications, post treatment, and testing a typical valve part requires.

Bob also describes some other failings of the counterfeit components:

The dimensions and material of construction obviously have significant impact on the performance and service life of a valve component. However, another significant benefit is associated with OEM parts: the knowledge and expertise of the manufacturer itself.

Over a part’s life cycle, it is constantly evaluated by the vendor, and often modified to improve its performance. When a replacement is purchased, the user is taking advantage of that refinement and obtaining a replacement that typically performs even better. The OEM also has expertise to recognize when process conditions have changed, and another component might be a better option. Meanwhile the non-OEM supplier simply provides the same substandard component, doomed to fail again and again.

Non-OEM part horror stories
A massive fire in India’s Hazira gas plant forced the immediate shutdown of the plant’s operations, blocked production from several gas fields, and curtailed 40% of India’s gas supply. The cause was traced to a set of non-OEM gaskets and O-rings installed in a gas meter during refurbishment. When the meter was returned to service, the seals failed and sparked the blaze.

In another incident, an end user sent a control valve to an unauthorized repair facility for refurbishment. The valve was repaired and returned to site and placed into service (Figure 4). Upon startup, the valve started leaking and forced the plant to shut down again.

Figure 5: An unauthorized valve repair shop decided to replace the actuator shaft assembly with a reverse engineered version (right picture). The non-OEM part dimensions were incorrect and kept the valve from fully closing.

An investigation determined the repair shop had replaced the actuator shaft assembly with a non-OEM part which was not dimensionally correct. The valve could not close, so the plant ultimately incurred an additional 24 hours of very costly unexpected downtime, a result of trying to save a few dollars on a $200 part.

Conclusion
The case studies presented here are just a small sample of the thousands of non-OEM valve components encountered daily in industrial plants and facilities worldwide. Valve bodies have failed, internal seal components have quickly deteriorated, and control valves and bodies have leaked —all due to the use of non-OEM parts.

Bob concludes his article with this note of caution:

A repair savings of a few hundred dollars can easily result in an unplanned loss and equipment damage worth hundreds of thousands of dollars. Is that deal worth the risk? Certainly not when the results can include extended downtime, associated economic loss, equipment damage, environmental incidents, injury to personnel, civil lawsuits, increased insurance rates, and long-lasting damage to a company’s brand and reputation.

All figures courtesy of Emerson, except Figure 1 which was reprinted from the Department of Energy’s Suspect/Counterfeit Items Awareness Training Manual.

About the Author

Bob Boyle is Vice President of the Fisher Parts Business Unit at Emerson. Prior to joining Emerson, he spent 20 years with Deere & Company in a variety of roles related to aftermarket, precision agriculture, business strategy, and M&A. Boyle holds a Bachelor’s degree in Management from the University of Maryland, and an MBA and a Master’s in Finance from Loyola University Maryland.

Article: Proper Valve Stem Sealing Best Practices

mark.nymeyer — Tue, 31 May 2022 12:44:29 GMT

Emerson Automation Solutions Senior Engineering Manager Lisa Miller recently published an article in the May/Jun 2022 issue of InTech. It is titled “Proper Valve Stem Sealing Best Practices” and it describes how control valve stem sealing works, and shows how to select the best option for each particular application. A summary of the article follows.

There are many different methods of sealing valve stems on control and isolation valves. When chosen wisely, a valve stem seal can provide years of reliable service, reduce environmental emissions, and minimize product loss. When chosen poorly, valve stem seals can leak consistently, increasing costs, creating environmental issues, and even placing operating personnel at risk.

This article explains various methods of achieving optimal valve stem sealing, helping end users evaluate the best choice for their application.

What are valve stem seals?
Control and block valves are typically one of two types: sliding stem or rotary. A sliding stem valve has a rod protruding from the body that rises and falls to actuate the valve. A rotary valve has a shaft extending out the side that is connected to a plug, disc, or ball. As the shaft turns, the rotary valve opens and closes. In either design, the valve stem must exit the body and be capable of relatively friction-free movement, yet contain the process media. This is not an easy task, as the author explains:

Valve stem seals must accomplish two contradictory goals. First, they must seal the valve stem completely and reduce - ideally eliminate - any fugitive emissions from the process. Secondly, they must accomplish this feat while allowing the valve stem to move freely and continue sealing, even as the valve stem cycles thousands of times.

Measuring stem seal performance
The three main industrial standards addressing valve stem leakage are TA Luft, FCI 91-1, and ISO 15848. However, the required performance and test methods for each standard varies significantly.

TA Luft is the least comprehensive standard, offering leak rate standards but no test parameter details. FCI 91-1 is more closely aligned to EPA’s LDAR program and uses the EPA Method 21 to “sniff” the valve packing and determine the leak rate (Figure 1). This standard does provide details on how a valve is to be tested, offering various classification ratings based on the leak rate after a specified number of mechanical and thermal cycles.

Figure 1: This Fisher GX control valve is subjected to EPA’s Method 21’s “sniff” test to determine the fugitive emission leak rate after a prescribed number of mechanical and thermal cycles.

ISO 15848 is much more involved, listing several leakage classification rates for both control and isolation valves based on mechanical cycles, thermal cycles, and stem size. It allows testing using helium or methane, and it dictates specific ways to precisely measure leakage.

Lisa notes that it is important to determine how a valve was tested when comparing stem seal performance.

It is relatively easy to achieve very low leakage rates if the valve is mechanically cycled a small number of times. It is much more difficult to achieve and maintain very low leakage rates when the valve is mechanically cycled thousands of times while enduring thermal cycles as well.

Sealing valve stems with packing
Most valves use a series of PTFE or graphite rings that encircle the valve shaft to provide a stem seal (Figure 2 - left). The rings are compressed with a combination of a packing follower, packing flange, and bolts to push down and squeeze the packing rings against the shaft. This arrangement allows the valve stem to move, while keeping process media from escaping.

Figure 2: This picture on the left shows a rising stem control valve with standard packing. More modern packing designs, such as the Fisher ENVIRO-SEALTM shown on the right, employ compressed Belleville springs to maintain constant pressure on the packing rings.

To achieve and maintain low emissions, packing must be ‘live loaded’ to keep constant pressure on the sealing rings (Figure 2 - Right). Compressed Belleville springs maintain a constant force on the packing, ensuring it seals even as the rings wear from stem movement. Unfortunately, the increased pressure tends to restrict valve movement, so the sealing materials and valve stem finish must be carefully chosen.

Sealing valve stems with bellows
An alternative option is a valve bellows seal. A bellows seal utilizes a welded or mechanically formed metal barrier around the valve stem that can compress and stretch like an accordion (Figure 3). The metal seal achieves virtually zero leakage.

Figure 3: Bellows seal designs usually employ a welded leaf design (detail left and middle) or a mechanically formed design (right). A formed design can withstand many more cycles than a welded leaf design, but it is usually about three times longer.

Bellows seal either use a welded leaf bellow seals (Figure 3 left and middle) or a formed bellows (Figure 3 right). The welded leaf bellows employs a stack of welded washer-like plates, providing many folds over a given length. A formed bellows uses a flat sheet of metal formed and welded into a tube which is mechanically formed. The welded leaf design is usually one third smaller than a formed bellows, but a formed bellows typically lasts significantly longer.

Packing versus bellows
Each method of valve stem sealing has pros and cons, and the best choice is very application dependent. Standard or environmental packing usually costs much less, and there is a wide variety of valve packing materials and designs to suit most applications. Valve packing can also be adjusted and replaced without disassembling the valve. The disadvantage of packing is the variable nature of its performance over its lifetime and the fact that it cannot achieve zero leakage. Small leaks can be addressed by tightening the packing, but at some point, the packing must be replaced.

The biggest advantage of a bellows design is its ability to deliver zero leakage, which is critical for lethal service applications. However, the operational life of a bellows seal is based on the number and length of strokes, so at some point it will fail. While this failure is more predictable, the repair requires the valve to fully disassembled, so the total cost of ownership for a bellows seal is much higher.

Ultimately, the best design decision will vary with each application, but an optimum choice can dramatically impact a plant’s bottom line as Lisa describes:

Proper selection of valve stem sealing is a critical component of the valve specification process. When chosen wisely, the design offers reliable long-term performance, translating into significant reductions in environmental emissions, product losses, and maintenance costs.

The number of design options are extensive, so end users may find it helpful to consult with their valve vendor to determine the best sealing design, materials of construction, and other details for their specific application.

All figures courtesy of Emerson

About the Author

Lisa Miller is a senior engineering manager for Fisher sliding stem valves at Emerson Automation Solutions. She has been the primary technical consultant for Fisher packing and bellows for over 20 years, and she has 25 years of expertise with cryogenic valve design, testing, and manufacturing. Miller is the chairperson of ISA75.27.01 "Cryogenic and Low Temperature Seat Leakage Testing of Control Valves" committee, and she has been a member of ISA for 10 years. She holds a BS in mechanical engineering degree from the University of Iowa.

Article: Alternative control valve repair solution yields savings

mark.nymeyer — Mon, 16 May 2022 12:37:59 GMT

Emerson recently published an article in the March 2022 edition of Processing Magazine. The article is titled “Alternative Control Valve Repair Solution Yields Savings” and it describes how a new hybrid repair/replace control valve repair solution can reduce repair time by 60%, while increasing plant uptime considerably. A summary of the article follows.

Traditional valve repair
Control valve repair is an expensive and challenging aspect of plant maintenance. These types of valves can be quite costly, so a simple replacement of the valve rarely makes financial sense. Therefore, the plant has little choice but to pull the valve, disassemble it, and identify and replace the failed components. However, a valve is composed of a broad array of internal parts (Figure 1), and it is difficult to determine which has failed until the valve has been fully disassembled. Even assuming all the parts required for the repair are available, the job is quite daunting as Emerson explains:

It takes a fully trained technician to diagnose, repair and properly reassemble the valve to restore it to functionality. Adding to the difficulty, the precision required to do this work means it can typically not be performed in the field, but instead must be done in a repair shop.

Figure 1: Control valves have many internal components that may require replacement during a repair, and all must be available before even starting. Proper reassembly of these numerous parts is critical for valve performance.

Once the repair is complete, there is still the risk that the problem was never fully identified, and the “repaired” control valve may fail to perform. It may also be reassembled incorrectly. In either case, the result is curtailed production, and possibly a complete unit shutdown.

Fortunately, a new option dramatically simplifies the control valve repair process with a streamlined approach, using a single assembly instead of multiple small parts.

Trim cartridge alternative
A new method of control valve repair has recently been introduced, offering significant advantages. A trim cartridge (Figure 2) is a single, pre-assembled repair solution that replaces all the components shown in Figure 1. This includes a valve bonnet, standard trim and packing replacement parts—as well as a plug and seat assembly.

Figure 2: A trim cartridge replaces up to 20 individual internal components with one drop-in assembly. Installation requires minimal training and makes inline valve repair possible.

Emerson describes the new repair component:
A trim cartridge is a single, ready-to-install repair solution containing all the replaceable trim parts incorporated in a pre-assembled, leak-tested, and serialized package.

The valve repair is fast and quite simple, usually requiring little technical training since it only involves replacement of the bonnet and trim (Figure 3). With proper line isolation, the repair can be completed without removing the valve body from the line, further conserving valuable trained technical resources, and significantly reducing downtime.

Figure 3: A trim cartridge installation replaces the bonnet and all trim parts, and it can be performed without removing the valve body from the process.

The trim cartridge has an added benefit as Emerson explains:

The repair replaces all serviceable parts plus the bonnet and does not require significant field adjustment. This dramatically improves the likelihood that the repair will be successful the first time.

The Fisher trim cartridge is backwards compatible for Fisher easy-e ET and EZ series control valves, and it incorporates ENVIRO-SEAL packing as a standard offering. It is offered in valve sizes from one to four inches, with a wide variety of trim and component materials, and both linear and equal percentage trims.

Evaluating options
Any successful maintenance strategy considers the cost of equipment repair against the cost of replacement to determine the most cost-effective option. The trim cartridge offers a hybrid alternative, allowing plant personnel to perform a partial replacement that quickly restores a control valve to service, an approach well suited for emergency repair of critical valves. It also allows a plant to easily upgrade to Enviroseal packing to reduce emissions. When a plant is faced with an overworked maintenance staff and is under pressure to make valve repairs quickly, a trim cartridge repair solution is often the best option.

All Figures courtesy of Emerson

Article: Staying Ahead of Environmental, Social, and Governance Goals

mark.nymeyer — Mon, 09 May 2022 20:49:25 GMT

Bruce Ofori, Emerson’s Sales Development Manager for ESG, recently published an article in the Mar 2022 edition of Hydrocarbon Processing. It’s titled “Staying Ahead of Environmental, Social, and Governance Goals” and it describes how forward thinking industry leaders are acting now to get ahead of government-mandated environmental, social, and governance requirements. A summary of the article follows.

The concept of only investing in firms that champion environmental, social and governance (ESG) issues has been discussed for decades (Figure 1). But after years of inaction, the idea is finally transitioning to reality as investors and stakeholders are now actively demanding that companies engage in ESG improvements and publicly show their progress.

Figure 1: Activists and investors are increasingly demanding companies to focus on ESG issues, set goals, and show continual progress and improvements.

These demands have been heard at the highest levels, as Bruce explains:

The calls have been so great that the U.S. Security and Exchange Commission (SEC) is creating reporting guidelines so companies can provide consistent and accurate accounts of their ESG programs, alongside their standard financial reports.

With so much public focus on these concepts, strong ESG performance is no longer a differentiator, but simply a requirement for many corporations. Though the standards and guidelines are in flux, proactive companies are already setting and pursuing ESG goals.

ESG in the oil & gas industry

While social and governance issues apply universally, the petrochemical industry is facing significant public pressure to improve their environmental stance by cutting emissions and reducing greenhouse gas generation. They usually accomplish this with a multipronged approach (Figure 2).

Figure 2: Most oil and gas companies pursue a broad variety of methods to reduce greenhouse gas generation and emissions.

The first method pursues low carbon fuels by utilizing recycled and renewable feedstocks, such as soybean oil, corn oil, beef tallow, used cooking oils, rapeseed, and others. In addition, processes are used to collect biogas from agricultural and waste sources and converts them to saleable biomethane.

Further environmental improvements stem from the reduction of methane emissions. Remote oil and gas production areas often use natural gas to operate instruments and valves, venting methane continuously. Also, many valves and pumps leak pollutants through packing and seal leaks. All these emission sources can be curtailed and even eliminated through proper equipment design and upgrades.

In addition, advanced controls tactics and strategies offer numerous ways for processing facilities to improve yields and run more efficiently, reducing waste and emissions even further.

ESG improvements through automation

Like oil and gas companies, automation industry firms are also trying to reduce emissions. Most have focused on internal processes, reducing building energy costs, and improving manufacturing efficiency and cutting waste, but those efforts ignore the best opportunity for ESG improvement, as the author describes:

While all these methods certainly have a positive impact on the environment, the most dramatic environmental improvements come from the development of new instrumentation and controls which enable oil and gas companies to achieve their ESG goals in a more effective and less costly way.

Membrane technology, control systems, and advanced analytics are used to automate and improve hundreds of biomethane processing plants all over the world, converting potential greenhouse gas emissions to market quality natural gas.

New designs in valve actuation allow natural gas-actuated valves to be replaced or inexpensively retrofitted with low and zero emission alternatives. There are also low bleed or very low power electrical alternatives for natural gas-powered instrumentation, with power provided by small local solar systems. The devices not only meet the stringent methane emission regulations for the U.S. and Canada, but they often pay for themselves in a short time.

Bruce suggests the time to act is now:

The demands from shareholders, stakeholders, the SEC, and the public in general for improvements in ESG initiatives are becoming insistent. Rather than wait for new regulations to be issued, most industry leaders are staying ahead of the curve by defining their own goals, tracking progress, and publishing results.

Obviously, the improvements immediately benefit society and the environment, but by proactively pursuing ESG goals, a company is allowed to define its role and choose the best path forward. This is almost always preferable to having governmental entities dictate goals and methods.

All Figures courtesy of Emerson.

About the Author

Bruce Ofori is the Sales Development Manager for ESG at Emerson for their flow controls products. He works with global customers to help them achieve their emission and energy reduction targets. Bruce is a graduate of the Kwame Nkrumah University of Science and Technology in Ghana with a bachelor’s degree in Chemical Engineering, and he obtained his Master’s in Petroleum and Gas Engineering from the University of Salford in Manchester, England.

Burst Mode Enable/Disable

Shaiq Bashir — Thu, 28 Apr 2022 18:58:37 GMT

Can somebody confirm if we can disable the burst mode on DVC6200 positioner while the valve is in service? or do we have to take the valve out of service to disable burst mode?

Regards

Valvelink on Trex calibrators

jeff richards — Tue, 19 Apr 2022 13:45:10 GMT

I am using the standard valve link as is the default install on our Trex units to carry out set-up and diagnosis of DVC6200 AD and PD positioners. I can use the step change functions to analyse dynamic response, but when making changes to dynamic response parameters, I cannot find the stabilise / optimise routines. When I log out of valvelink, I can find them in the generic HART application and I can use them, but then I have to go back into valvelink to progress with analysing the modified response. Is there a reason why I cant find stabilise / optimise inside valvelink?

Also, I cannot find the performance tune function that should be available on both the PD and AD positioners. I cannot find this in either the Trex unit version of Valvelink or in the generic HART application. Can you advise how I can access this performance tuner function.

Regards

Jeff Richards

Article: Simplifying control valve packing selection

mark.nymeyer — Wed, 05 Jan 2022 20:29:52 GMT

Emerson Automation Solutions’ technologist Wade Helfer and simulation engineer Sarah Witte recently published an article in the December 2021 edition of Processing. The article is titled “Simplifying control valve packing selection” and it describes how increasingly stringent environmental regulations have complicated valve packing selection. A summary of the article follows.

Historically, valve packing design has been a relatively simple part of the control valve selection process. A control valve was chosen to provide the necessary flow performance at specific process temperatures and pressures, and the packing was usually specified by the vendor to match the process data.

Packing selection has become a much more involved process as the EPA lowered emission limits to 500 ppm, then 100 ppm, and even 50 ppm in some cases. Now, the packing design process can be very challenging and critical to valve selection.

What is packing?

Before discussing the packing selection process, it is best to describe how packing functions. Control valves typically have a reciprocating rod or twisting stem that move the valve plug to control flow. Regardless of the design, the valve stem must exit the body and be capable of relatively friction-free movement, yet still contain the process media and avoid leaks. Valve packing makes that possible.

The sealing portion of a valve packing usually consists of a series of Teflon (PTFE) or graphite rings that encircle the valve shaft (Figure 1). The rings are compressed from above, squeezing them against the shaft, to seal and contain the process.

Figure 1: This picture shows a typical rising stem control valve. The packing consists of the packing box (#3), the packing rings just above it (#2), and the packing follower, packing flange and bolts mounted above.

While a tight seal against process leaks is necessary, it is just as important that the compressed rings allow the valve stem to move freely, since a stuck or bound stem impacts a valve’s ability to control flow of the process media. In the past, emission requirements were less stringent, so free movement was considered more important. This changed with the new Clean Air Act Amendments, as the authors explain:

Packing designs were simple, and so was packing ring selection, as it was primarily based on process temperature since only very high process pressures impacted packing. All that changed when fugitive emission reduction became a priority for the EPA.

Valve packing emissions for hazardous and targeted chemicals have been steadily dropping with each round of regulation, and this has driven a whole host of alternative packing designs to meet the standards.

Environmental packing designs

One way to meet low emission requirements is “live loading” the packing (Figure 2). Spring-loaded Belleville springs are compressed during installation to maintain a constant force on the packing, ensuring it seals even as the rings wear.

Figure 2: Modern packing design uses compressed Belleville or other special springs to maintain constant pressure on the packing rings. This ensures the fugitive emissions are limited to 100 PPM or less, even as the rings wear.

Live loaded packing designs greatly reduce fugitive emissions, but the high compression increases stem friction and degrades control valve performance. PTFE seals well and lubricates the shaft, but it is only rated to 450 at limited pressure. Graphite rings can handle temperatures to 1000 and pressures to 4000 PSI, but they do not seal nearly as well as PTFE. Graphite also tends to restrict stem movement at lower temperatures.

Some valve vendors address these issues by utilizing advanced materials and improved packing configurations (Figure 3). Layers of carbon or glass reinforced PTFE and graphite, as well as alternative materials such as KALREZ, are used to extend pressure and temperature limits, while still meeting emission requirements.

Figure 3: Advanced environmental packing arrangements use carbon reinforced PTFE, graphite, or combinations of reinforced PTFE and graphite rings, to handle higher process temperatures and pressures while keeping emissions low.

Unfortunately, there are some environmentally sensitive applications where the process conditions exceed the temperature and pressure ratings of these advanced packing designs, but there is yet another design option.

High temperature modeling

In most valve configurations, the packing is located on the valve stem and somewhat separated from the valve body. This often means the packing will not encounter the full process temperature as heat radiates away from the valve bonnet. The resulting temperature differential provides an opportunity to utilize the superior sealing and lubrication of PTFE-based packing above its temperature rating. The authors describe how this works:

Finite element analysis can be employed to model the heat signature of a control valve body and bonnet during process conditions. This thermal model can be used to predict the maximum temperature encountered by different sections of the packing.

The simulation models (Figure 4) are based on an advanced understanding of the valve’s heat transfer properties as well as extensive lab testing, and this effort enables new packing design options.

Figure 4: Advanced modeling and simulation programs allow vendors to predict the maximum temperature of the packing components, allowing superior performing packing materials to be used.

Once temperature models are created and validated, the data is used to create custom packing designs that include a combination of graphite packing in the high temperature zones and reinforced PTFE packing in the lower temperature areas. This revised design handles high temperature and pressures, meets the emission requirements, and has improved lubrication and longer service life.

Packing selection summary

The authors suggest end users follow these steps when selecting control valve packing:

Determine the pressure and temperature of the process media.
Know the valve type (rising stem versus rotary) and valve manufacture and model (which may limit the available packing options).
Determine if the valve must meet specific fugitive emission standards or not. (Air, steam, nitrogen, water, etc. will generally not require low emission packing, but natural gas and most hazardous chemicals will.)
Compare the material compatibility of the process media with the various packing seal options offered by the valve vendor.
Based on that information, consult the packing options for the chosen valve model to determine what packing materials and designs will meet the requirements. The selected packing should meet emissions standards and minimize stem friction movement. Environmental packing designs may be a good option even if there is no low emission requirement because they provide superior sealing performance and very low friction.
If a standard packing offering cannot handle the temperature and pressure conditions, investigate if the valve vendor has temperature models available that might enable a combination of packing materials to meet the application requirements.

Wade Helfer is a technologist at Emerson and is responsible for developing and evaluating new control valve technologies with an emphasis on mechanical systems. He has 23 years of industry experience in the design and evaluation of control and isolation valves for a variety of industries. He completed his BS degree and graduate coursework in mechanical engineering from Iowa State University.

Sarah Witte is a simulation engineer at Emerson. She has four years of industry experience at Emerson in the evaluation of control and isolation valves utilizing Finite Element Analysis with a focus on thermal analysis. She completed her B.S. degree in Mechanical Engineering from Iowa State University.

RV: cotizacion valvulas proyecto endulzamiento de gas Cupiagua

VICTOR HUGO ZABALA — Thu, 23 Dec 2021 23:51:00 GMT

Señores Emerson Valves, cordial saludo

Por favor me colaboras con el costo presupuestal de las válvulas de control que te describo en el cuadro adjunto

Anexo hoja de datos y MR.

Favor confirmar recibido.

Favor informar datos del representante en Colombia

Atte.

Victor Hugo Zabala C

Industrial - Contrato 3024515

Estimación de Costos

SGS Colombia S.A. – ETSA.

Cra. 7 No. 32-42 (Piso 34)

Bogotá, Colombia

Móvil: 3133859751

Email: victor.zabala@ecopetrol.com.co

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Article: Select the Right Control Valve Materials

mark.nymeyer — Thu, 23 Dec 2021 17:29:02 GMT

Brett Hofman, additive materials engineer for Emerson, recently published an article in the November 2021 edition of Processing. The article helps demystify the design process for selecting proper valve component materials and is titled Select The Right Control Valve Materials. It is summarized below.

When faced with a bewildering number of options, it can be very challenging to choose the best materials of construction for control valves. Each valve component may have a different set of critical property requirements, and there can a whole host of processes which might be acting to degrade or destroy them. Brett explains the problem:

“There are many reasons for control valve component degradation, including erosion, adhesive wear, flashing, cavitation, corrosion, temperature extremes, and others. Several of these challenges often occur simultaneously, so it is important to identify and understand each problem.”

Erosion physically removes material from a part due to particulate in the process fluid. Adhesive wear results when metals rub against each other. Flashing damage (Figure 1, left) can occur when a liquid passes through a valve and the downstream pressure is below the vapor pressure of the liquid. The boiling liquid tends to wear the metal over time. Cavitation (Figure 1, right) involves boiling liquid as well, but in this case the pressure recovers as it moves through the valve and collapses the vapor bubbles. The resulting microjets and shock waves can inflict significant damage.

Figure 1: Flashing damage (at left) can be significant, but cavitation (at right) is usually much more destructive. Cavitation damage also makes a valve much more susceptible to corrosion.

Corrosion comes in many forms and is chemically induced (Figure 2). General corrosion occurs with uniform attack on a metal, such as the rusting of steel or iron. Pitting corrosion is a localized attack that leaves deep pits in metal that might otherwise be unaffected in other areas.

Figure 2: General corrosion (at left) attacks all surfaces of a part evenly, while pitting corrosion (at right) attacks localized areas, often leaving the rest of the part unscathed.

Brett describes other forms of corrosion:

The list of corrosion types goes on and on, including stress corrosion cracking (SCC), crevice corrosion, intergranular corrosion, galvanic corrosion and many others. The hardest part of battling corrosion is understanding what chemical process is in play because, in many instances, there are several types of corrosion occurring simultaneously.

Identifying Key Parameters

Each valve component is designed to meet specific performance criteria, and that knowledge figures heavily in the material selection process. Some of the typical material properties include strength, wear resistance, thermal expansion, corrosion resistance, and creep resistance. These critical material properties vary significantly from part to part (Figure 3).

Figure 3: This figure illustrates how each valve component requires very different critical material properties. Note that this figure is generalized and may vary based on valve design and process conditions.

Strength (or hardness) measures how a material resists cutting, scratching, or bending. Wear resistance indicates how well a material absorbs energy. Thermal expansion and corrosion resistance are self-explanatory. Creep resistance is a solid material’s ability to avoid slowly deforming over long periods of stress and high temperatures. The best material for a particular application depends on how that component is being used in the valve.

Know your material options

The number of materials options for control valve components is expansive, and the breadth of proprietary and generic names often leads to confusion. There are over 20 versions of “Hastelloy” metals and at least six different alloys called “Inconel”. When referring to alloys, it is often best to use a UNS number or ASTM standard.

It is also important to understand how a particular metal protects against corrosion so it can be applied appropriately. Some materials employ an oxide layer that provides passive corrosion resistance. These materials tend to work well in oxidizing environments but work poorly in reducing environments, which attack the oxide layer. Other materials are inherently inert and are less reactive in a variety of environments. Figure 4 lists a variety of materials, along with their various strengths and weaknesses.

Figure 4: This table is a small sample of the many materials available, and the wide range of corrosion, wear, and erosion resistance offered by each.

Brett offers the following advice for choosing the best material:

Clearly, the number of options is huge, and the price differential from one alloy to another can be significant. When faced with a difficult material selection decision, it is advisable to discuss the options with your valve vendor. Often, several alloys may work, and the best choice for your particular application may be a combination of valve design and valve component material selection.

Brett Hofman is an additive materials engineer for Emerson, researching how to realize the potential of additive manufacturing technologies in Emerson’s products. He previously held the role of Materials Engineer for Emerson’s flow control products, providing materials technical support on a global level to various departments across the company. He graduated from Iowa State University with Bachelor of Science degree in materials engineering in 2016.

serial cards question

hast66 — Sat, 02 Oct 2021 17:39:27 GMT

I have serial cards of some of our control valves

But I find it hard to find out which item is the one I need. (What's in a name). I have not much experience with control valves. I'm new to Installed Base Tool too

There seems to be no reference drawing with key numbers available?

How should I handle this?

Also where can i find missing serial cards?

Thank you

Flow control valve specs

James Doell — Thu, 16 Sep 2021 21:19:25 GMT

I need the specs for a control valve: Model#667, size 70. serial #21181873

specifically I'm looking to find out what the maximum flow rate is for steam at 100% open on this valve. If there is a spec sheet that would be great.

Article: Choked Flow in Control Valves

mark.nymeyer — Mon, 30 Aug 2021 20:44:41 GMT

Katherine Bartels and Adam Harmon, both Design Engineers at Emerson, recently published an article in the August 2021 of InTech. The article describes the poorly understood phenomenon of choked flow, and shows how it can affect control valve sizing and trim material selection. The article is titled Choked Flow in Control Valves and is summarized below.

Choked flow in control valves is often a serious concern for industrial users. Most associate the term with destructive process conditions that can damage valve internals and generate very high noise levels, but choked flow does not always cause these conditions.

This article describes the phenomenon of choked flow and explains why it occurs. It also explains when choked flow conditions are damaging, and shows how this damage can be reduced or avoided.

What is choked flow?

If the inlet pressure (P₁) and valve flow area are fixed, the flow through a valve will normally rise as the downstream pressure (P₂)is reduced. The “Ideal” line in Figure 1 illustrates this point, showing how liquid flow rises linearly versus the square root of the valve differential pressure divided by specific gravity.

Figure 1: In an ideal world, flow rate through a valve rises as the pressure drop across the valve increases. In reality, the maximum flow will be limited due to choked flow conditions.

However real-world flow does not match ideal flow, as the authors explain:

In actuality, the maximum liquid flow through the valve can never exceed a choked flow limit, and at this point flow will increase no further, no matter how low the P₂ pressure is reduced.

A similar phenomenon occurs with valves in gas service. If the P₁ pressure and flow area remain fixed, flow through the valve will rise as P₂ is reduced, but at some point, choking will occur and the flow remain constant, regardless of the value of P_2.

Why does choked flow occur?

Choked flow occurs for different reasons in liquid applications versus gas/vapor applications. In liquid applications, choking is a result of the reduction in pressure through the restricted port area as shown in Figure 2. As the liquid moves from the larger inlet area to the reduced plug/ seat (vena contracta) area, it must accelerate significantly to pass the flow.

Figure 2: This graph shows a typical pressure curve of a cavitating liquid passing through a control valve. If P₂is reduced still further, the expanding vapor will create an increasing pressure drop and eventually limit flow.

Bernoulli’s law states that the total energy at every point in the flow stream is constant, so if velocity is increased, pressure must fall. This pronounced pressure dip in the vena contracta becomes more pronounced as flow increases.

If the instantaneous pressure in the vena contracta falls below the vapor pressure, then vapor bubbles will begin to form as the liquid begins to boil. The conversion to vapor increases the volume of the fluid and begins to restrict flow. If the downstream pressure is lowered still further, the vapor volume will increase to the point that flow throughput can increase no further, and the valve flow becomes choked.

Choked flow in gas/vapor applications occur for different reasons, as Kathrine and Adam explain:

In gas applications, the vapor velocity through the valve will increase until the vapor reaches sonic velocity. At this point, the vapor can go no faster because a standing shock wave forms and limits flow. Further reduction of the downstream pressure will have no effect on flow through the valve.

Choked flow misconceptions and issues

Choked flow by itself does not directly damage a valve, but there are flow conditions commonly associated with choked flow that can create problems, including:

Flashing and cavitation: A common misconception is that choked flow conditions require flashing conditions, but choked flow can occur under cavitating conditions as well. As shown in Figure 3, cavitation will result when the P₂ pressure rises above the vapor pressure of the liquid. When this occurs, the bubbles collapse and turn back into liquid. If the P₂ pressure remains below the vapor pressure, the liquid will boil and flash to vapor as it passes through the valve, and remain a vapor as it exits (Figure 3).

Figure 3: This graph shows a typical pressure curve of a flashing liquid passing through a control valve. Fluid enters the valve as a liquid and exits as a vapor.

Either flashing or cavitation may result in choked flow, but not always. However, if flow is choked in liquid service, a significant level of cavitation and/or flashing will probably be present.

Noise levels: Choked flow does not directly create noise, but high noise will often result during choked flow conditions. In liquid applications, cavitation or flashing creates noise, with the noise level increasing as flow and/or pressure drop are increased

With vapor flow, noise will rise significantly as the velocity turns sonic. As the downstream pressure is reduced, the extra energy is converted to sound energy. Valves handling a high pressure drop can generate sound levels greater than 100 dB.

Valve damage due to choking: Users often assume choked flow conditions will damage the valve. However, there are times when a valve is choked and the damage is minimal, and there are times when the valve is not choked and the rate of damage is significant.

Sustained cavitation will almost always damage the valve. Flashing will eventually damage the valve as well, but the effect is less dramatic and immediate. Excessive noise can also damage the valve due to high vibration and metal fatigue.

Fortunately the authors explained there are options to address these issues:

Cavitation, flashing, and noise damage can be alleviated and even eliminated by specifying appropriate valve body designs, special valve trims, and materials of construction (Figures 4 and 5).

Figure 4: This graph compares the vena contracta pressures of a high recovery (ball, butterfly) valve versus a low recovery (globe) valve for the same process conditions. A high recovery valve creates significantly lower internal pressures, increasing the likelihood of cavitation.

Low recovery valves (such as globe valves) or special anti-cavitation trims (Figure 5) can either reduce cavitation, or focus it away from valve internals and walls.

Figure 5: Special valve trims, such as the Emerson Fisher Whisper III trim shown, can be employed to attenuate noise, reduce cavitation, or direct cavitating liquids away from valve components—all of which minimize damage to the valve.

Hardened alloys can be used for critical valve internal components to extend valve life. Noise can be significantly reduced by using low noise trims, inlet and outlet noise attenuators, or downstream modal noise attenuators.

The authors conclude with this advice:

When faced with the possibility of choked flow, or if there are concerns or questions on how to proceed with valve sizing or selection, contact valve vendors for technical support. They can usually provide valve sizing programs that predict when choking will occur and its impact on valve sizing and selection. They can also help users choose the best combination of materials and trim designs to alleviate damaging conditions.

Figures all courtesy of Emerson.

About the Authors

Adam Harmon is a Senior Design Engineer at Emerson Automation Solutions, with a focus on valves in Steam Conditioning applications. He graduated with a BS in Mechanical Engineering from Iowa State University and has been with Emerson for 11 years.

Katherine Bartels is a Design Engineer at Emerson Automation Solutions, with a focus on custom anti-cavitation valves. She graduated with a BS in Mechanical Engineering from Iowa State University and has been with Emerson for 6 years.

Article: Switching on to Electric Control Valves’ Potential#

mark.nymeyer — Wed, 07 Jul 2021 14:16:10 GMT

Scott Losing, Engineering Program Manager at Emerson Automation Solutions, and Andrew Prusha, Global Upstream Oil and Gas Manager for Emerson’s Flow Controls Products, recently published an article in the Issue 2, 2021 of Oilfield Technology. The article describes how electric control valve drives are helping oilfield operators address methane emission regulations and maximize production. The article is titled Switching On To Electric Control Valves’ Potential and is summarized below.

Wellheads are often located in very remote sites, lacking both compressed air and power, so their pneumatic controls are frequently powered by natural gas. While these controls work well, they can be prone to maintenance problems if the gas quality is poor. More troublesome, they continuously vent methane. Limiting this venting has been targeted by numerous countries to curb methane emissions (Figure 1).

Figure 1: Recently introduced by the US Environmental Protection Agency (EPA), CFR 40 Part 60 Subpart OOOO seeks to dramatically reduce methane emissions.

New standards are forcing wellhead operators to either replace natural gas-driven pneumatic devices with low bleed alternatives, or to instead install air compressors for powering the devices. In either case, significant CAPEX may be required.

Fortunately, there is another alternative, made possible by advances in electronic drive technology and the availability of limited power at well sites from solar systems, batteries, and small natural gas generators.

Electric Valve Drives

New powerful, low-cost electric drives have recently been introduced that can be easily retrofitted to many existing control and on/off valves. Scott and Andrew describe their capabilities:

These drives only require low voltage (12V and/or 24V) and low current, while providing fast and reliable control along with diagnostics. This gives users the ability to satisfy the new methane reducing environmental regulations while providing remote control and monitoring of their well sites. More importantly, the new drives and instrumentation enable profitable, advanced control strategies that were not easily implemented before these upgrades.

Here are just a few of the many new control options enabled by this technology.

Oil Separator Level Controls

An oil separator is a simple process device that uses gravity to separate well fluids into oil, water, and gas (Figure 2). Water collects upstream of the weir, oil flows over the weir, and gas leaves the top. In remote well sites, simple on/off control is used to maintain an oil/water interface about halfway up the weir, along with a sufficient level of oil on the back of the weir to keep gas from escaping.

Figure 2: An oil separator uses gravity to separate incoming well fluids into gas, oil and water.

Unfortunately this coarse method of control tends to create pulses of oil and gas which are difficult to measure. Flow is often understated, reducing profits. However, electronic control valves provide an alternative, and much better, solution. These valves can be programmed to operate in a linear fashion, so oil and gas flow become continuous. This results in tighter level control and better flow measurement. The authors describe the result:

Electronic control valves were recently employed on a number of oil separators in North Dakota, US. The control improvements reduced gas loss down the oil line by 80% and improved oil flow measurement accuracy by 5%, effectively increasing well production.

Gas Lift Enhancements

Another area of opportunity is improved control of gas lift. Gas lift injects pressurized natural gas down the well annular space to reduce the well fluid density and help push the liquids up the well (Figure 3). Gas lift can increase production, but it results in a loss of natural gas. Therefore the gas flow must be metered carefully, providing just enough to improve oil production.

Figure 3: Gas lift uses natural gas injected at the base of the well to help push fluids to the surface. Electronic controls and valves enable more advanced control schemes to maximize production, while minimizing wasted energy and natural gas usage.

Pneumatic controls are typically set once during start up and left unchanged. However, electronic controls and control valves can automatically adjust the flow to optimize production as conditions change, increasing net profit.

Plunger Lift Control Schemes

Plunger lift is used on ageing gas wells when falling well pressure becomes insufficient to push entrained liquids to the surface. These liquids can pool at the bottom and eventually stop all gas flow. Plunger lifts usually employ some type of plunger to help push the liquids up the well (Figure 4).

Figure 4: Plunger lift uses a plunger and trapped wellhead pressure to push liquids to the surface.

The controls block the gas flow at the top, let the plunger fall to the base of the well, and then release the gas when the well has pressured up. The surge of gas drives the plunger and any liquids to surface, allowing the gas to flow until the liquids build up again. Another plunger cycle is then started.

Plunger lift control requires logic to detect falling gas flow and automate the plunger cycle. There is also significant advantage to controlling the rate of gas flow surge so that it drives the plunger correctly but does not overwhelm downstream flow measurement. Electronic drive control valves make all this possible, generating significant cost improvements, as Scott and Andrew describe:

Electronic transmitters and control valves enable plunger lift operations and are able to control and measure the resulting gas surge flow. This improved gas flow measurement saves about US$85,000 a year on an average well.

Rod Lift Flumping Controls

Rod lift is another enhanced recovery method, using a downhole pump to push liquids to the surface (Figure 5). The gas pressure in the well must be carefully controlled or the gas flow can vapor lock the pump, reducing efficiency and production. This condition is known as “flumping”.

Figure 5: A rod lift well can experience reduced liquid production due to ‘flumping’ when high gas flow from the well creates vapor lock conditions on the pump.

Electronic controls and valves can be used to maintain enough backpressure on the well to maximize gas flow, while maintaining liquid production. The elimination of flumping can generate approximately US$2000/day in increased production on a 250 bpd well.

Conclusion

When considering a wellhead instrument upgrade, it is worth the time to investigate the latest technology. Implementing electronic transmitters and electric control valves can significantly increase production and improve your bottom line.

Figures all courtesy of Emerson

About the Authors

Scott Losing has 20 years of design and development experience with Emerson flow computers and control valve actuation. He completed his BS in Computer Engineering Iowa State University and is the Engineering Program Manager at Emerson Automation Solutions for their Fisher™ easy-Drive™ Electric Actuators.

Andrew Prusha is Global Upstream Oil and Gas Manager for Emerson’s Flow Controls products in Marshalltown, IA. He has seven years of experience representing Fisher valve & instrument products from a variety of roles.

Article: Advanced Valve Diagnostics Drive Savings

mark.nymeyer — Tue, 29 Jun 2021 16:36:17 GMT

Brent Baker, Fisher Instrumentation Product Manager, and Jordan Mandernach, Fisher Instrumentation Software Product Manager, recently published an article in the June 2021 issue of Plant Engineering. The article describes how smart valve positioners can be coupled with diagnostic software to significantly reduce maintenance costs and shorten plant shutdowns. The article is titled Advanced Valve Diagnostics Drive Savings and is summarized below.

Prediction is Challenging

Predictive maintenance has been the goal of plant personnel all over the world. In theory it is a fantastic idea. If the plant can predict when equipment is beginning to fail, it can react proactively to plan and resolve developing issues before they blossom into equipment failure and unexpected shutdowns.

While simple in concept, predictive maintenance can be devilishly difficult in practice, since prediction is not so easy. How can one determine when a critical control valve is starting to fail? This can be especially difficult since the control loop often masks deteriorating valve performance until it fails completely, creating significant process upsets.

To avoid unexpected failures, many plants simply pull and inspect every control valve on a routine basis. This method usually detects developing problems and reduces unplanned failures, but it comes at a price. The resulting maintenance costs can very high and the work often extends plant outages.

A Better Way

Fortunately there is an alternative method to address these issues, as the authors explain:

There is another option, made possible by advances in smart positioner diagnostics (Figure 1). Armed with an array of sensors, a digital position controller is uniquely placed to monitor the control valve and detect abnormal conditions as they develop.

Figure 1: Smart positioners, like this Fisher FIELDVUE DVC6200, employ an array of sensors to detect air, actuator, packing, and valve problems well in advance of total valve failure.

Smart positioners can detect developing issues and communicate this information to an asset management system, where it can be highlighted and addressed. Any base level smart positioner offers self-calibration features to ease valve setup, but some positioners have capabilities well beyond that and can be used to create a valve signature for a new valve (Figure 2). This signature captures myriad performance details that can be compared to future valve signature test results. Such a comparison quickly identifies developing issues.

Figure 2: Valve signature information can be captured when a control valve is commissioned and compared against future stroke performance to highlight developing problems and troubleshoot failing components.

More advanced positioners can monitor valve performance while the valve is online, noting when a valve fails to reach commanded states or exhibits abnormal behavior. Other positioners can be programmed to detect specific events and capture historical data associated with them. This data can be invaluable to help technicians troubleshoot and resolve valve problems. Top-tier positioners enable partial stroke testing even when a valve is online.

Developing a Diagnostic Program

Taking advantage of positioner diagnostics starts by evaluating the current state of the plant positioners. Much of the equipment required may already exist. If possible, digital signatures of each valve stroke should be captured to create a baseline of data.

The next step is to identify mission critical valves and update those positioners as necessary to obtain the diagnostics needed. Some positioners can be upgraded to incorporate higher levels of diagnostics without replacing the whole unit.

The final step is install the necessary software, and establish communication networks to capture valve data and alert relevant personnel to developing problems (Figure 3). Data has minimal value if it is not transferred to the right person in a timely manner.

Figure 3: Diagnostic data is only useful if alerts are transferred to the correct personnel and acted upon quickly.

Diagnostic data is particularly useful when planning shutdown work because it indicates which control valves need repair and which do not.

Real World Savings

The authors describe three cases where plants realized significant savings by taking advantage of smart positioner diagnostics.

A herbicide plant in Iowa reduced annual maintenance costs by $230,000 by using advanced control valve diagnostics to transition their plant from reactive to predictive maintenance. In one case alone, the plant saved nearly $100,000/hour by detecting and addressing a developing control valve issue before it shut down the unit.

A paper mill in Louisiana was suffering routine boilers trips due to damper positioning problems. Upgraded smart positioners with advanced diagnostics eliminated these trips, avoiding losses of $18,000 an hour due to unscheduled outages.

A combined cycle power plant was reworking all critical valves during every outage in an effort to maximize uptime when the plant returned to service. After installing a number of upgraded digital valve positioners and implementing diagnostic alert software, the plant was able to focus their outage repair efforts more efficiently. The plant saved $68,000 in one outage alone, and it has experienced year-to-year cost reductions of $33,500.

Prediction is no easy task, but the advanced diagnostics available in smart, digital positioners can go a long way towards helping maintenance staff do exactly that.

All Figures are courtesy of Emerson.

About the Authors

Brent Baker is a Product Manager for Fisher Instrumentation at Emerson with 14 years of experience. He spent 12 years as an instructor and content developer for Emerson Educational Services, focused on training customers and Emerson personnel on the installation, operation, maintenance, and troubleshooting of Fisher control valves and instrumentation. His current role responsibilities include support for current Fisher Instrumentation and new product development.

Jordan Mandernach is a Software Product Manager for Fisher Instrumentation. He has 8 years of experience in the process control instrumentation and software industry. His background is in new product development and software marketing.

Article: World’s First Commercially Available Modal Suppression Device

mark.nymeyer — Mon, 14 Jun 2021 13:22:57 GMT

Bill Flowers, senior director for Fisher rotary valves at Emerson, recently published an article in the June 2021 issue of Hydrocarbon Engineering. The article describes a newly patented, full bore, passive attenuator that provides broad spectrum sound level reduction with no pressure drop. The article is titled Sound Suppression and is summarized below.

High aerodynamic noise levels are a natural result of turbulent flow. As gas or steam flows through a control valve, velocity increases in the seating areas and then slows, creating pressure fluctuations and sound waves. Lighthill’s law states that aerodynamic noise varies as the eighth power of gas velocity, so high flow and high pressure drop applications get very loud, very quickly.

High noise levels can damage hearing and destroy valve internals, so it must be addressed. The two main methods of noise reduction are source control and path control, with each varying in cost and effectiveness.

Addressing the Source

Source control diminishes noise levels by eliminating or reducing sound using pressure drop staging or flow division. Pressure drop staging reduces the overall noise by dividing the total pressure drop over several steps, rather than taking the full drop at a single point. The reduction in velocity reduces the sound.

An alternative source control method is flow division, which breaks up the single flow path into multiple flow paths. More paths reduce velocity and create lower levels of sound.

In either case, source control often requires a more complex valve internal design, which is costly and prone to plugging.

Upstream or downstream external diffusers combine both pressure drop staging and flow division, but they add cost and usually incorporate very small flow passages, which can plug.

Sound Path Suppression

Path control is an alternate means of aerodynamic noise reduction. The author describes this method:

Path control attempts to muffle the sound and keep it from radiating to the surrounding area. The techniques can be as simple as thick walled pipe, pipe insulation, or encasing the pipe with acoustic blankets or materials designed to absorb the sound. Alternatively, one can employ specially designed silencers which either absorb the sound or use resonant chambers to cancel the noise through destructive interference. A car muffler is an example of a resonant chamber silencer that is common in everyday use.

Silencers work, but they usually create a high pressure drop and a tortuous path, and they may include sound absorbing materials which degrade over time. Acoustic blankets wear with exposure to the elements and are often damaged or improperly installed after maintenance, so their performance also declines over time.

An Alternative Emerges

Both source and path controls do work, but as discussed, they each have significant costs and limitations. Unfortunately these were the only noise reduction choices available until a very different sound reduction technology entered the market. The new device has only recently been introduced, but it is based on a forty-year-old concept.

In the early 1980s, a graduate student named Ali Broukhiyan published his honors thesis on a new method of control valve aerodynamic noise reduction called a “Modal Coincidence Suppression Device” (Figure 1).

Figure 1: This diagram shows the original concept of a modal coincidence suppression device, designed to reduce the aerodynamic noise produced by a control valve. The series of chambers are each sized to produce destructive interference across a small range of frequencies.

The design consisted of a series of concentric rings around a pipe, with each ring designed to resonate at a particular range of frequencies. When installed downstream of a noise producing control valve, the device created destructive sound interference across a range of frequencies, reducing the overall sound level.

Early trials of the technology were encouraging, but there was no way to economically construct such a device. The concept was abandoned and shelved for decades.

Resurrection Through Additive Manufacturing

After being forgotten for years, the modal suppression device suddenly became a viable option as the author explains:

The advent of additive manufacturing and 3D metal printing enabled Emerson to create complicated metal components that could never have been economically fabricated in the past. New and innovative anti-cavitation and low noise trims were the focus of early additive manufacturing efforts, but attention eventually turned to the modal coincidence suppression device.

After several years of testing and refinement, Emerson developed and patented a means to fabricate a sound suppression device. Emerson’s WhisperTube will be released for sale in late 2021 and will be offered in sizes from 2” to 12”, with flange ratings of 150, 300, and 600lb (Figure 2).

Figure 2: The forged Whisper Tube (6” model shown) undergoes noise testing at the Emerson Innovation Center Flow Laboratory.

The new modal suppressor is similar to the original concept but incorporates several improvements (Figure 3). The inner pipe is a full bore perforated liner, and the new design includes a larger number of concentric cavities, providing an average 10dB noise reduction across a broader range of frequencies.

Figure 3: The modal suppressor consists of cylindrical chambers of varying sizes surrounding a full bore perforated tube. Each chamber generates destructive interference over a small range of frequencies to provide significant noise reduction across a broad spectrum.

In addition, the rings have been modified to allow the device to be self-draining, so process liquids do not collect in the rings and negatively impact performance.

A New Option for Noise Reduction

The modal suppression WhisperTube offers a variety of advantages over other noise reduction technologies. It is a simple, passive device offering a 10 dB average noise reduction across a broad range of frequencies (Figure 4).

Figure 4: Concentric rings of various sizes create broadband noise reduction as shown in this chart.

This new design is full bore and generates no pressure drop. Less expensive butterfly valves can be paired with this device to provide a lower cost option, as compared to a typical globe control valve with low noise trim. Finally, the self-draining version can be utilized for steam and two-phase flow applications where liquid accumulation would adversely affect many other noise abatement designs.

All Figures except Figure 2 are courtesy of Emerson. Figure 2 supplied from a public domain thesis.

About the Author

Bill Flowers is the Senior Director for Fisher rotary valves at Emerson. He has global product responsibility for Fisher pipeline ball valves, eccentric plug valves, and all types of actuators. Flowers has been with Emerson for 33 years and has held roles in engineering, global sales, research and development, and product management.

Problem in sizing 3 way Valve fisher specification manager

Amir — Sat, 29 May 2021 13:12:04 GMT

Dear Friends

As you are completely aware , three-way valve bodies having three flow connections, two of which can be inlets with one outlet (for converging or mixing flows), or one inlet and two outlets (for diverging or diverting flows). in both case we have 3 connection. but when I start to size valve with Fisher Valve Specification Manager (Sizing application), and select three way as style in installation data tab , I could not find any items related to entering data related to connection ( nominal Pipe Size , End connection) and only there are one inlet pipe size and one outlet pipe size. moreover ratio combination can not be found.

Dear Experts please guide me about mentioned issues.

Thanks in advance

Article: Next Gen Trim Reduces Rotary Valve Cavitation

mark.nymeyer — Fri, 23 Apr 2021 19:51:53 GMT

Brandon Bell, product manager for Fisher rotary flow control products, recently published an article in the March 2021 issue of Oil & Gas Engineering. The article described a new rotary valve anti-cavitation trim, and a recent refinery application where the trim solved significant operations problems. The article is titled Next-gen Trim Cuts Rotary Valve Cavitation and is summarized below.

Rotary-style control valves are common across many industries because they’re relatively inexpensive for a given line size and have high flow capacities. However, the low recovery factor of these designs makes them prone to cavitation. Brandon describes the problem:

Cavitation poses serious problems for control valves. .As a liquid passes through the valve restriction, increased velocity creates a low-pressure zone that effectively boils the liquid and creates vapor bubbles in the flow stream. As the fluid passes beyond the trim and velocity slows, the pressure returns and the vapor bubbles collapse creating shockwaves that can severely damage valve components and piping.

Equipment damage is amplified if the process fluid contains erosive particles, as the following case study illustrates. Brandon continues:

A refinery in Louisiana encountered a situation that constituted a worst-case combination of cavitation and erosion. The application involved a control valve passing large quantities of river water laden with fine silt. The flow rates and line size demanded a rotary valve, and the pressure drop across the valve was high. The valve typically exhibited high cavitation noise and vibration.

The cavitating river water with entrained silt exited the 10” rotary globe valve and impinged on the wall of the downstream piping, eventually causing it to breach (Figure 1).

Figure 1: Downstream piping fails due to extreme cavitation and the erosive effects of river silt. Note the river water spraying out of the pipe at the bottom left of the photo. Courtesy: Emerson

To avoid costly downtime, the control valve was proactively replaced every 24 months, and the downstream piping was replaced every 6 to 12 months. This situation continued for years.

Historically, anti-cavitation trim options for rotary valves have been limited, with most manufacturers only offering some type of attenuator integrated into the ball of the valve. These devices are at best partially successful for reducing cavitation, providing varying effectiveness at differing degrees of rotation, and tending to divert the process fluid toward the valve body and piping, damaging those areas.

Additive manufacturing options

Fortunately, recent advances in additive manufacturing enabled improvements in anti-cavitation trim designs. This manufacturing technique enables specialized trim designs that would have been impossible or prohibitively expensive just a few years ago. One of these new designs is the Cavitrol Hex anti-cavitation trim offered for the Fisher Vee-ball rotary control valve (Figure 2).

Figure 2: Anti-cavitation trim embodies a design enabled by additive manufacturing. The trim can be retrofitted to existing valves and works well at any throttling position. Flow enters the above diagram from the left. Courtesy: Emerson

Unlike previous designs, this rotary valve anti-cavitation trim is inserted into the valve from the downstream side and is not connected to the rotating ball in any way. This allows the trim to perform as desired regardless of the degree valve opening, and it can be retrofitted into any existing Fisher Vee-ball valve.

The specialized flow channels reduce cavitation within the valve and direct the process fluid straight downstream, eliminating wall impingement and pipe damage.

Successful river trial

At the previously mentioned refinery, the existing rotary valve was replaced with a Fisher Vee-Ball valve with Cavitrol Hex anti-cavitation trim. Cavitation noise and vibration abatement was immediately apparent. After a year in service, the valve was pulled and inspected (Figure 3).

Figure 3: After a year in service there was no sign of downstream piping damage. Courtesy: Emerson

No damage to the downstream piping was detected, and damage to the valve was limited to erosion of the lower section of the anti-cavitation trim face. After the initial inspection, Emerson offered an upgraded trim composed of higher hardness R31233 alloy. The valve was returned to service for another year.

The next annual inspection found small rocks trapped in the trim, but there was no damage to the downstream piping or the valve body, and minimal erosion damage to the Cavitrol Hex trim (Figure 4).

Figure 4: The anti-cavitation trim was replaced with a higher hardness R31233 alloy and returned to service for another year. The next inspection found a few small rocks stuck in the trim, but no damage to downstream piping, no damage to the valve body, and greatly reduced erosion damage of the Hex trim. Courtesy: Emerson

Brandon notes:

The valve remains in service to this day, and the refinery remains extremely pleased with the valve’s dramatically improved performance.

Author Bio: Brandon Bell is a product marketing manager for Fisher rotary flow control products based in Marshalltown, Iowa. He has been with Emerson for over 20 years with prior experience in the areas of test & evaluation, product engineering, and new product development. Brandon is a prolific inventor with nine US patents and has a Bachelor of Science in Mechanical Engineering from Kansas State University.

Article: Troubleshooting Issues and Eliminating Headaches Related to Control Valves

mark.nymeyer — Thu, 22 Apr 2021 19:51:36 GMT

Sean Raymond, technical marketing manager for Fisher Instrumentation with Emerson Automation Solutions, recently published an article in the April 2021 issue of Power magazine. The article describes troubleshooting techniques for control valve problems and is titled Troubleshooting Issues and Eliminating Headaches Related to Control Valves, and it is summarized below.

“That new control valve is acting up again!” Similar words have been uttered by thousands of control room operators in power plants all over the world. The plant is not running well, and operators are quick to identify the culprit—a recently installed, misbehaving control valve. It might be cycling, it might be squealing, it might sound like it has rocks going through it, but it is definitely the cause.

Or is it?

Sean describes the situation.

When troubleshooting control issues, it is important to keep an open mind and look beyond the obvious. It is human nature to blame the “last thing changed” for any new problem that occurs. While erratic control valve behavior might be the apparent source of concern, the true cause is often located elsewhere.

Here are some application examples to illustrate his point.

Squealing control valve

A high-pressure spray valve was squealing after a few months of service. The valve was pulled, checked, and appeared to be functioning normally. When returned to service, the squealing resumed, and the plant demanded the “defective valve” be replaced. A little checking indicated the valve was being cycled by the control system between 0 and 10% open at a rate of 250,000 times a year. A little loop tuning and backpressure on the valve stopped the cycling and eliminated the squeals.

Jumpy valve response

A boiler feedwater pump recycle valve was sticking in the seat at startup. When the valve would first come off the seat, it would jump to the open position, creating control upsets (Figure 1).

Figure 1: A boiler feedwater pump recycle valve would jump 15 to 20% open (shown by the green line) when it was first activated, creating major issues due to surging flows.

Diagnostics were run and the air supply pressure was found to be set well above specification, four times higher than required for adequate seating. The high pressure damaged the seat and seal, causing the valve to hang.

Strange control valve behavior

A new control valve acted erratically while in operation, with flows surging and the valve swinging. Online diagnostics were run—and adjustments were made to the positioner tuning, supply air pressure, and pneumatic relays—but the problem remained. Ultimately, the source of the behavior was found to be a leaking bypass valve.

Identifying the Issue

Sean describes how to identify valve problems.

When troubleshooting a control issue, the team should start by fully understanding and identifying the problem. Often, operators will fixate on a single effect (such as erratic flow control, control valve behaving oddly, or noisy equipment) and complain about that.

One has to pose the right questions to obtain a more complete view of the problem. Probing questions often expose contributing conditions and take the investigation in an entirely different direction.

Troubleshooting tools, if available, are also helpful. Historical data and process trends might expose contributing factors such as surging pressures, swinging flows, or other process variations that could be causing the problem. Digital positioner diagnostic tools can shed light on how the valve is performing (Figure 3).

Figure 2: Diagnostics can be performed on valves to pinpoint problems.

But be careful as data can be misleading. Poor resolution or slow update times on a trend may mask problems or imply issues that may not exist. Also, valve diagnostics have their limitations since positioner data is only as good as the position information it receives (Figure 3). If the linkage is loose or worn, the indicated position will not match the true position.

Figure 3. Worn linkage components can create problems for a valve positioner. The worn valve coupler on the left will mislead the positioner into indicating the valve is moving when it is not.

Systematically eliminate causes

When armed with a full understanding of the issues and relevant data, one can begin to track the root cause. Start by identifying all possible culprits and then systematically eliminating them through further testing. Sean concludes:

When faced with a control problem, go in with open eyes and an open mind. Look beyond the obvious source of the issue. As Sherlock Holmes said: “It is a capital mistake to theorize before one has data. Insensibly one begins to twist facts to suit theories, instead of theories to suit facts.”