Prevent varnish issues: How to keep your turbine oil in top condition

EPT’s SVR™ Lube Oil Conditioning System:
Game Changing Lubricant Management

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Questions on 7F inspections? Get answers in Schaumburg

The ability of gas turbines to meet expectations depends to a large degree on regular inspections by experienced technicians equipped with the diagnostic tools capable of finding and evaluating potential problems before they adversely impact engine operation. Equally important is guidance on what to inspect and how often, and exactly what to look for “under the hood.”

Users rely heavily on the OEM for timely alerts and advice on issues as they are experienced in the fleet. One way this is done is by release of a Technical Information Letter (TIL, GE terminology) describing a specific concern, how to inspect for it (when and how often thereafter), how to correct findings, etc.

User group meetings like the 2019 7F annual conference, May 20-24, at the Renaissance Schaumburg, a few miles from Chicago, provide valuable perspective on the development of an optimal inspection plan for your plant. Formal presentations and open discussions allow the opportunity to relive the experiences of plant colleagues and listen to what the leading inspection companies are finding in their field work.

Snippets of valuable inspection-related information are sprinkled throughout every 7F program. At the 2018 meeting, the steering committee tried to aggregate some of this information in an “NDE Roundtable” with participation by the OEM, Veracity Technology Solutions, and Advanced Turbine Support. Team 7F didn’t want to restrict the dialog and suggested the following as possible discussion topics:

    • Compressor findings—clashing, cracking rocking, twisting, etc.

    • NDE inspections on enhanced compressors.

    • Combustion findings—fuel-nozzle leaks, transition seals, etc.

    • Turbine findings—cracks, clogged cooling holes in buckets and vanes, etc.

    • AGP hardware findings.

    • Which NDE techniques to use and why.

    • New NDE techniques.

In addition, inspection experience was sought on the following TILs: 2069 (1-2 spacer rim inspection), 2006-R2 (airfoil distress on third-stage bucket), 1972-R2 (conical flat-slot bottom compressor wheel), 1937-R1 (turbine-wheel inspection), 1907-R1 (forward shaft dovetail crack), and 1769 (aft-stator rocking).

Obviously an ambitious program for the hour allocated for the NDE Roundtable. The session could have filled a productive half-day workshop—in the opinion of the editors. A few of the topics addressed follow.

Register now for the 2019 7F conference.  There will be plenty of opportunity to get your inspection-related questions answered at the Schaumburg meeting—at user-only sessions on the compressor (Tuesday) and turbine (Wednesday) sections, during GE Day on Thursday, at meals, in the hallways, and at the vendor fair. Regarding the exhibit hall, inspection experts from Advanced Turbine Support will be on hand in the exhibit hall Tuesday and Wednesday evening at Booth 57; Team Veracity will be at the vendor fair on Tuesday in Booth 73.

Plus, don’t forget to sit in on the first series of vendor presentations Wednesday afternoon and listen to what Veracity President Kevin McKinley has to say about “Advanced NDT Protocols Needed for End-of-Life Assessments of Gas Turbines.”

GE

Flat slot-bottom findings. The OEM reported that inspections have revealed indications requiring part replacement at around 2400 to 5000 actual starts on FA.02, .03, and upgraded .04 machines. The GER 3620 recommendation was said to take precedent at 5000 factored starts. Recommendation: Inspect at 1700-2200 starts to obtain indication size and determine operational safety.

Inspections completed to date have confirmed TIL 1972-R2 inspection recommendations and that they are necessary to determine true rotor capability.

Third-stage bucket distress. The 7F users were told that five third-stage bucket (S3B) liberations had occurred since mid-2013, each within 8000 hours of operation following repair and creep rejuvenation heat treatment. The affected units were 7F.01-.03 machines, plus a few Dot 04s running with second-tour buckets.

The liberation events initiated either at the leading edge of the airfoil at 40% to 50% of radial span, or at the trailing edge at 20% to 30% of radial span. Total hours on the failed buckets ranged from 25,000 to 55,000 hours. TIL 2006-R2, dated January 2018, provides corrective actions identified during the OEM’s RCA.

Note that TIL 2006 was first released in July 2016 to provide mitigation during the RCA process. Eddy-current inspection was added to the OEM’s repair process the following January and its creep rejuvenation cycle was updated in May 2017 to improve ductility and the tolerance of buckets to damage.

1-2 spacer wheel rim inspection. TIL 2069 applies to both 7F and 9F-class turbines. It was issued following the inspection of a 9FA that had tripped on high vibration. Technicians found a section of the spacer rim had liberated and caused significant collateral damage. Operating data provided no early warning of the incident: Vibration levels, wheelspace and exhaust temperatures, etc, all were normal.

Multiple initiation locations were observed on the inner surface of the spacer rim which then propagated radially and circumferentially outward through the spacer rim. The RCA identified the propagation mechanism as hold-time fatigue, an hours-based phenomenon.

Recommendation is that the inspection prescribed by TIL 2069 be performed along with the wheel inspection suggested in TIL 1937, during the first HGP or major after the spacer wheel completes 80,000 hours of operation. At a minimum, the turbine casing must be removed to provide the necessary access.

Veracity Technology Solutions

Tulsa-based Veracity discussed its experience fulfilling the requirements of TIL 1509, “F-Class Front-End (R0, S0, and R1) Compressor Inspections.” The company reported being called to a 7FA site for a routine TIL 1509 inspection in mid-2018. The document’s recommendations were said to be important, and “required” by the OEM. One reason: Engine availability and reliability can be compromised by front-end compressor rubs, which are conducive to metal liberation and downstream damage.

TIL 1509 was said to be a good example of an inspection that benefits from using multiple NDE techniques to deliver very reliable results. Veracity relies on both the eddy-current method and its proprietary ultrasonic phased-array (UTPA) technology, originally designed for the Dept of Defense. Use of these two methods, the company says, yields the highest probability of detection over alternatives because it can find cracks on both the pressure and suction sides of R0 and R1 blades in-situ.

Case in point: A tip crack on an R1 blade was detected. On its own, this does not sound like news of any sort, but it’s where the crack was located that may lend credence to the use of UPTA technology for this type of inspection. The 0.67-in. crack was found on the back (pressure) side of the blade, 3 in. from the trailing edge (photos).

Those familiar with the R1 blade’s anatomy know this area is a “meatier” part of the airfoil and this indication could not be seen from the suction (front) side. It also is an area not typically inspected because of limited access.

According to Veracity’s Scott Kennedy, the crack would not have been located using the typical penetrant (PT) or eddy-current (EC) techniques employed in the field. UTPA allows for simultaneous capturing of both sides of the blade, thereby providing a full-coverage inspection.

Summing up the advantages of UTPA for a TIL 1509 inspection:

    • Timely compared to PT.

    • Very sensitive to small flaws.

    • Can inspect both sides of the airfoil from either side.

    • Not necessary to scan the entire length.

    • Provides a permanent record.

    • Can size flaws.

Eddy current’s advantages include the following:

    • Extremely timely compared to PT.

    • Very sensitive to small flaws.

    • Can detect material flaws and hardness changes that are precursors to stress risers.

    • Known minimal detectable calibration.

For the case history described, after technicians discovered the indication with UTPA, they validated the indication with a near-field borescope and with a borescope-assisted EC inspection.

Advanced Turbine Support

Mike Hoogsteden opened the company’s brief presentation by reviewing the leading-edge inspection tools used by the company’s technicians—including phased-array ultrasonic, eddy-current array, and specialized surface inspection methods. While advanced NDE equipment allows the company to go above and beyond what the OEM typically asks for in its TILs, he mentioned there are instances where tried-and-true legacy methods may provide optimal results. He put visible dye penetrant in this group.

Hoogsteden stressed the company’s ability to provide 100% NDE coverage of all R0 and R1 airfoils. He added that Advanced Turbine Support has never missed an indication or crack in its R0 and R1 inspections. On the turbine end of the machine, Hoogsteden said the company’s eddy current array gear proved itself in a qualification run for a major utility to meet the requirements of TIL 2006 (see above) in evaluating the condition of third-stage buckets. Inspectors identified all of the surface and subsurface indications in the validation block.

Referring to TIL 1972-R2, he showed photos to illustrate the detection and crack-sizing information achieved for flat-slot-bottom compressor wheels when the surface condition allows.

Still more photos confirmed the considerable capabilities of advanced NDE in finding dovetail cracking in the forward shaft (TIL 1907), plus confirmation with liquid penetrant.

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Come up to speed on turbine fluids and their care at the 7F Users Group meeting

The 2019 annual conference of the 7F Users Group, May 20-24, at the Renaissance Schaumburg (Ill), provides an opportunity to update your knowledge on turbine lube and hydraulic fluids—both their selection and maintenance. As of April 1, three lubricant suppliers had committed to participating in the vendor fair along with six aftermarket services providers offering fluid inspection, analysis, and reconditioning services.

Consider visiting with the following business partners of CCJ ONsite while at the expo:

A suggestion: Take a few minutes to think about what you need to know about turbine fluids and their care to help avoid operational hiccups at your plant. Arrive in Schaumburg prepared to maximize the benefits of participating in the world’s largest independent user group serving owner/operators.

In turbine lubrication, like most areas of power-generation technology, there are no panaceas, no one-size-fits-all solutions. You have to do your homework to determine the best lubricant for your situation and the best way to manage its condition to assure maximum life. Talk to colleagues and subject-matter experts, read articles from back issues of CCJ (the search function at www.ccj-online.com is convenient for this purpose), scour user-group websites for back presentations, etc.

There may be no better way to learn about what works and what doesn’t, in given situations, than from colleagues. Consider the following, shared by the operations manager (formerly the maintenance manager) at a plant with two 2 × 1 7FA-powered combined cycles. This user has been at the facility since before it began commercial operation in 2002, making his perspective and experience particularly valuable in an industry challenged by retirements of its most skilled personnel and high turnover rates in plant staffing.

The lubricant selected for all four gas turbines at the subject plant, which today start about 100 times during a typical year and run about 5000 hours, was a popular mineral-based product provided by a leading oil company that was said to meet or exceed the requirements of all turbine OEMs. “Exceptional” thermal/oxidation resistance was another claim.

IGV issues surfaced in 2004 with varnish inhibiting proper operation of the inlet guide vanes during cold-weather starts. First “fix” was to install heat tracing on all oil lines to keep the varnish in solution.

In 2007, the plant took a more aggressive approach to resolving the problem: Sump was pumped and flushed. All “sorts” of gunk was removed, the user recalled. Refill was with ACT’s EcoSafe®-TF-25. This was the second commercial use of the TF-25 product, the first being at a nearby plant a couple of weeks earlier. Budgetary considerations militated against converting the site’s other gas turbines to TF-25.

Bear in mind that while heat tracing is not necessary on fluid-system components handling TF-25, it continues in service at this plant for mineral oils.

During a major inspection in fall 2018, the TF-25 sump was revisited and found in near-pristine condition after a service run of more than 47,000 hours and more than 1600 starts (photo). Turbine bearings and seals also were inspected during the outage and found clean.

What makes this plant a particularly good one for gaining objective experience on lubrication practices is that the sister unit of the gas turbine running with TF-25 continues to operate on the original oil supplied with both engines. Varnish issues have been mitigated by use of a commercial skid-mounted system that relies on resin technology to remove dissolved varnish precursors.

The two turbines serving the second combined cycle at the site were switched about 10 years ago to an alternative mineral oil (different brand than the original oil) as part of a beta test. The units have operated since without a varnish removal system.

However, varnish recently has been viewed as a possible concern and plant personnel are considering treatment with EcoSafe®-Revive™ to extend the productive lifetime of the oil. In the ops manager’s view, “it does as advertised” based on his research.

How long does it last? One question on the minds of many users evaluating lubricants: “What’s the long-term performance?” To get that answer for TF-25, 10-year-old PAG sample was entered into an industry-wide study conducted by Laborelec (Sidebar 1), which developed a test protocol involving six thermal cycles to simulate turbine operation (Sidebar 2). Twenty turbine fluids were evaluated on a level playing field to help turbine owner/operators make better decisions regarding lubricant selection and treatment.

1. Who is Laborelec?

Laborelec, today officially known as ENGIE Laborelec, is one of the world’s leading centers for research on electric-power technologies. Its objectives are similar to those of EPRI, familiar to most subscribers. Laborelec was founded in France in 1962, a decade earlier than the Electric Power Research Institute launched in the US.

ENGIE is a French multinational electricity provider claimed to be the world’s leading independent power generator with more than 115 GW installed and another 10 GW under construction. The company, formed as GDF Suez in 2008 with the merger of Gaz de France and Suez, was renamed ENGIE in 2015. It has more than 150,000 employees and business interests in more than 50 countries.

Laborelec, one of nearly a dozen R&D centers under the ENGIE umbrella, has 240 highly specialized engineers and technicians working across the electricity value chain. It is organized as a cooperative with ENGIE and independent grid operators as shareholders.

Key takeaways from the tests included the following:

    • Ten-year-old PAG bested new conventional and thermally stable mineral oils in RPVOT tests.

    • Ruler results showed “used” PAG was at least as good as all new fluids evaluated.

    • Acid number for TF-25 was relatively constant across the six thermal cycles and below the maximum recommended limit.

    • Membrane Patch Colorimetry results were 8 or less.

    • Fluid density remained relatively constant across the six test cycles.

Test results thus far indicate TF-25 may last 30 years, or more. This means some plants might not have to change their turbine oils before decommissioning.

2. How Laborelec evaluates alternative turbine fluids

The first step for assuring top performance from your turbine fluid is to choose the optimal product for your engine based on OEM recommendations and the plant’s operating profile. Your experience, and that of industry colleagues, should be factored into the selection process, of course.

It also is necessary to implement a proper maintenance program to maintain your turbine fluid in good condition throughout its operating lifetime. However, it’s important to re-evaluate this program regularly—annually, perhaps—and factor in operational changes that can influence fluid condition—such as a shift from baseload to peaking service.

Laborelec’s experts point out that once a turbine fluid enters service, it starts oxidizing, a process that promotes the formation of degradation products. The solubility of degradation products, in the case of mineral oils, is temperature-dependent: the lower the lube-oil temperature the more likely the degradation products are to plate out on turbine parts and impede operation of servos, inlet guide vanes, etc.

Backgrounder. The stress experienced by a turbine lubricant contributes significantly to the ageing of petroleum oil, causing the non-polar fluid to oxidize. However, the resulting byproducts of decomposition are polar and insoluble in the base oil; they come out of solution as “varnish.” By contrast, leading alternative turbine fluids—such as polyalkylene glycol (PAG)—are polar in nature and their byproducts of decomposition are infinitely soluble in the base stock. The bottom line: No varnish is produced.

Laborelec engineers and chemists were of the opinion that information important to decision-making on the selection of an appropriate turbine fluid for a given plant was not provided on the manufacturer’s technical data sheets. For example, a prospective customer might not know the service conditions considered in the development phase of turbine fluids of interest. All users had, basically, were some results of various ASTM tests.

In 2012, the research organization began work on the design of a test protocol to compare different turbine oils/fluids on a level playing field. First step was to meet with lube-oil suppliers, maintenance companies, and turbine OEMs to discuss their test specs.

This effort was the foundation for the development, in early 2014, of the “Laborelec Cyclic Turbine Oxidation Test.” The LCTO test protocol combines the “Standard Test Method for Oxidation Characteristics of Inhibited Mineral Oils (ASTM D943)—a/ka/ Turbine Oxidation Stability Test (TOST)—and the dry TOST developed by Mitsubishi Heavy Industries.

Test program. The results below obtained from the testing of 20 turbine fluids were interpreted based on the standard practice used for in-service monitoring of mineral turbine oils for steam and gas turbines (ASTM D4378-13 and VGB-S-416-00-2014-08-EN). The fluids were grouped into four categories for comparison purposes by turbine owner/operators and test participants—this to keep information on specific products anonymous. The categories: mineral oil (MO), thermally stable mineral oil (TSMO), high-performance mineral oil (HPMO), and PAG.

Lube-oil suppliers, of course, have access to their data, enabling a comparison of their fluids to the group performance of competitive products regarding speed of degradation and the formation of degradation products.

An important aspect of the test protocol is that each fluid was stressed to simulate real-world operating conditions. This was done by thermally cycling the test samples. For the purposes of the LCTO test, samples were heated to a nominal 250F and held at that temperature for four days. Sample temperature then was reduced to 77F and held there for three days. This cycle was repeated six times. Data were taken for the fluid when new and after each cycle.

Results illustrating fluid condition were divided into three zones as illustrated in the figure:

    • Normal (white field), no specific actions are recommended and the fluid can remain in service.

    • Follow-up (yellow field), beyond the normal acceptable value. At this stage, the first indicators of oil oxidation become visible. Corrective actions are necessary, but oil generally can remain in service provided monitoring is increased.

    • Out of spec (red field), indicates an on-going severe oxidation process. Immediate response typically includes specific maintenance actions to protect equipment from mechanical problems. Fluid replacement should be considered.

More detail is provided in the thumbnails below for each parameter included in the evaluation:

Color, ASTM D1500. Sample color darkens as the fluid degrades.

Fluid density at 20C, ASTM D4052, increases significantly.

Viscosity at 40C, ASTM D7072, exceeds ±10% ISO-VG class.

Acid number, ASTM D-664. Most rust inhibitors used in the formulation of new turbine oils are acidic and contribute to the acid number of the fluid. As mineral oils age, they form solids that precipitate out the amines, making the acid number rise. A maximum increase of 0.2 to 0.4 mg KOH/g of initial value is tolerable. Above 0.4, known as the condemning limit, is detrimental.

The best performers regarding acid number are the TSMOs which had acceptable acid numbers through six cycles. Mineral oils jumped out of spec after two cycles, while PAG received a caution flag after two cycles; HPMO went yellow in the first cycle but road through six cycles without hitting the condemning limit.

Note that ASTM D4378 refers to condition monitoring of in-service mineral oils and can create false-positive results or require modification for non-petroleum chemistries. For example, the Total Acid Number for PAG starts at approximately 0.11 with a condemning limit of 2.0. The result after the sixth cycle on TF-25 of <0.40 represents a favorable result well within specification.

RPVOT, ASTM D2272, is a controlled, accelerated oxidation test to measure the remaining level of anti-oxidants in lube oil. When the RPVOT value (units are minutes) of the oil drops below 25% of its initial value, fluid replacement should be considered.

PAG was one of the two best performers in this category. After six cycles, its RPVOT was still 75% of the new-fluid value; HPMO stole the show, retaining 95% of its anti-oxidant package at the end of the test period. Mineral oils “failed” after the second cycle, TSMOs after the fourth.

Ruler, ASTM D6971. Like RPVOT, oil change is recommended when 25% of the initial ruler value is reached. PAG got the yellow flag after two cycles when its Ruler value hit 50%. However, it continued on under the caution flag until testing was complete. Mineral oil was out of spec before the first cycle was completed; TSMO and HPMO each lasted four cycles.

MPC, a/k/a Membrane Patch Colorimetry, ASTM D7843, is a varnish potential test that identifies the propensity of a lubricant to form solid deposits, thereby helping maintenance professionals avoid catastrophic failures. MPC values greater than 30 require immediate attention.

Other tests included filtration (0.8 µm), as specified in ASTM D4055, and deposition (on glass tubing and catalyst coil), both with “dangerous zones” beginning at 100 ppm.

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How to mitigate risks associated with gas-turbine LCI starting systems

It’s no secret that many gas turbines are starting and stopping far more frequently than originally designed for. At the same time, independent system operators (ISOs) are imposing stiff fines for failure to meet startup and performance obligations.

Most plants have adapted to these more aggressive operating tempos and performance challenges, but one component that may be getting overlooked is the starting subsystem, especially for older machines equipped with a load commutated inverter (LCI).

According to John Downing, Turbine Control & Excitation Group (TC&E), the Innovation Series™ and LS2100 LCIs, introduced in the late 1990s and early 2000s, consist of three subsystems, or functions: control section, silicon-controlled-rectifier (SCR) bridge section, and cooling section. For units not originally designed for lots of starts, it was common to have one LCI for multiple GTs, often in a one-to-two ratio.

For nearly 25 years, the LCI has provided reliable service. However, with an expected life of 20 years, many have failed, and a substantial number are at, or past, end of life. Failures usually are experienced in the controls and/or the cooling system.

Downing told the editors that in 2017 TC&E responded to 17 forced outages attributed to LCI failures, between Memorial Day and Labor Day, that averaged 36 hours each. The costs associated with lost revenues and penalties for non-performance typically dwarf the costs of replacing or upgrading the LCIs to eliminate this particular source of failure.

Last production of the Innovation Series and LS2100 LCI controls supplied with GE machines was in 2013. Today, replacement parts are difficult to locate; acquisition times of four to six weeks are common. Also, qualified service and field engineering personnel are becoming harder to find as they retire out of the workforce.

Mitigating the risk. Options to address this risk include the following:

    • Complete replacement of the LCI.

    • Locate, purchase, and inventory critical spare parts, especially those relating to the control and cooling sections, and identify the engineers and technicians qualified to make the replacements when the time comes.

    • Install a “digital front end” (DFE) control section replacement. In this case, the controls are replaced with a modern alternative that extends LCI life by 20 years.

TC&E has partnered with TMEIC, one of the world’s largest manufacturers of LCIs and drives, to provide a turnkey DFE solution that Downing said is far less expensive than the other two options. TC&E/TMEIC also can offer the complete replacement, or additional LCI system, for every type of GE turbine—including large frames and aeroderivatives. The partnership has more than 15 LCI-experienced field engineers at its disposal.

Guts of the partnership’s offering are as follows: The obsolete programmable logic controller (PLC), standard VME (Versa Module Europa) rack, power supplies, and input/output (I/O) boards are replaced with new processor-based control circuit cards and a new PLC. The new digital controls fit in the existing panels and reuse most of the existing fiber optic cables and connectors (figure).

The upgrade includes a local color touch-screen control panel and HMI interface.

In the control center, the associated software suite expands the programming, control, optimization, troubleshooting, and data logging of onsite operations, engineering, and maintenance personnel. The new LCI DFE utilizes appropriate communications protocol to talk directly to the GE Mark VI and Mark VIe control systems.

The typical upgrade project can be accomplished in five to seven shifts; a turbine shutdown is not necessarily required, although, of course, the LCI will be unavailable for that period.

Users react. The degree to which the starting system is a financial risk may depend on the type of owner/operator organization, gas-turbine OEM, and age of the plant. Experienced GT engineers and plant managers contacted about this issue responded that the risk is minimal as long as plant staff is diligent about regular inspection and maintenance, especially of the cooling system components. The issue also may be limited to older machines from the GT boom period (1997-2003), many of which were designed for baseload service but rarely, if ever, ran that way.

All of the users contacted were not aware of an abnormal spike in GT starting-system failures, nor had they experienced failures at their facilities out of the ordinary.

According to one, LCI is a general term for one way to implement a medium-voltage variable-speed drive (VSD), variable-frequency drive (VFD), pulse-width-modulated drive (PWM), or static frequency converter (SFC). In other words, LCI, popular in the 1990s and early 2000s, is a very specific circuit and thyristor bridge arrangement that is different from other types of drives.

According to this source, they are less-expensive drives that have tradeoffs—such as harmonics reflected back on the power system—requiring additional isolation transformers, and often can have lower power factors and efficiency.

Many of the original LCI suppliers are no longer around or have broken up. When an issue arises, the OEM usually recommends replacing it.

Another seasoned GE gas-turbine controls expert adamantly stated that the LCI is very reliable, and “as long as you perform recommended maintenance and TILs (Technical Information Letter), it’s like a forgotten part of the plant.”

Nevertheless, many facilities are owned by financial engineering firms which are fond of cutting every penny of “unnecessary expense,” and sometimes cut too much fat and into the bone. As one user noted, this is very specialized and complicated equipment and very few people have spent much time with their heads in these cabinets.

If this sounds like your site, you might want to take appropriate action, especially since it does represent a single point of failure, regardless of how reliable the original components are.

To dig deeper, visit TC&E in Booth 3 (Tuesday) at the vendor fair of the upcoming 7F Users Group meeting. John Downing also will be presenting on LCI and exciter issues at 3:45 on Tuesday in Shaumburg EF.

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How to achieve reliable pressure regulation

Silverhawk Generating Station underwent a period in which the safety valve for the plant’s auxiliary steam system failed repeatedly, NV Energy engineers Rishi Velkar and Frank Romans told the editors. Consequences of the failures included frequent valve replacement and loss of production through forced outages.

Examination of the failed safety valves revealed seating-surface erosion associated with high-velocity steam flow. Historical process data (Fig 1) showed transitional phases where the auxiliary-steam pressure would breakdown into uncontrollable oscillations. Testimonials from plant operators conveyed the only means to stop the oscillations was through manual intervention.

During the course of startup, the auxiliary-steam control valve PV100 (Fig 2) is required to maintain constant downstream pressure with a supply pressure that varies from 110 to 1600 psig. Concurrently, operation of the condenser air ejector (hogger) introduces practically an “all-or-nothing” demand on the aux steam system.

A varying main-steam supply pressure, combined with extreme changes in demand, apparently caused the oscillations and subsequent safety-valve failures.

Comparison of the Silverhawk auxiliary steam system to arrangements used at other plants highlight a stark difference. Most others use two steam sources to supply the auxiliary steam system: main steam and reheat steam. Each has a control valve to regulate downstream auxiliary steam pressure.

The advantage of the two-source scheme: Auxiliary-steam control valves regulate downstream pressure for a much lower range of supply pressures. Thus, they are less likely to break down into oscillations.

Installation of a system similar to that used successfully by others is a possible long-term solution. For the immediate need, any solution had to incorporate existing equipment.

Solutions. Here’s what was done:

1. Modified the control-system program so the auxiliary-steam-pressure control algorithms used variable proportional and integral values.

Prior to this change, the proportional and integral values were constant. Now, these values change as the main-steam supply pressure varies. Deploying this strategy made the pressure-control response appropriate for a given supply pressure.

2. Changed the control scheme to mitigate the impact of “all or nothing” demand on the auxiliary steam system.

When hogging begins, the demand for auxiliary steam increases rapidly and steam pressure drops below that required for proper operation. Conversely, when the hogger is removed from service, the demand for aux steam drops to zero and its pressure spikes, typically causing the safety valve to open.

Changes to the control scheme comprised feedforward signals that adjust the steam-pressure regulator valve whenever the hogger is placed in, or removed from, service. Automatic changes to the aux steam pressure setpoint also occur.

Once the hogger begins operating, the regulator valve (PV100) opens an additional 6% to keep pressure at an effective level; the auxiliary-steam pressure set point stays at 105 psig (Fig 3).

Whenever hogging stops, the regulator valve (PV100) closes an additional 9% to limit the pressure increase. Simultaneously, the pressure setpoint drops to 75 psig. The lower setpoint holds for a period of 10 minutes. The 10-min hold assures the pressure stabilizes before the automatic return to the normal setpoint of 105 psig (Fig 4).  

3. The aux steam system must function throughout a variety of dynamic operating conditions. Obviously, the hogger is most critical, but other scenarios can upset the system as well. Installation of an “override” control scheme reduced sporadic opening of the safety valve.

The override activates when aux steam pressure exceeds 114 psig. While the override is active, the regulator valve (PV100) closes a percentage that is proportional to the rise of steam pressure above 114 psig. More specifically, an aux steam pressure slightly above 114 psig will result a small percentage of regulator-valve closing; a pressure significantly above 114 psig produces a higher percentage of valve closing (Fig 5).  

4. The company’s engineering team reviewed the aux steam piping system, concluding that the safety-valve setting was conservative and most likely determined during plant commissioning. The team decided to raise the safety setting to 140 psig, which allows a larger margin of operation.

Results. Since implementation and tuning of the 2018 solutions summarized above, there have been no safety-valve failures or loss of production hours (Figs 6 and 7). Additionally, the safety valve opened only once, in May, and a minor tuning change corrected the issue. Afterwards, the safety valve did not open again for the remainder of 2018.

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