RiTech® hard coating is a high-velocity oxygen fuel coating process using a hot, high-velocity gas jet to spray a coating of molten particles on to the ball and seat surfaces. Photo courtesy: ValvTechnologies

History shows us that valve failures can be catastrophic. Although it occurred in 2010, the effects of the Deepwater Horizon disaster can still be felt on the Gulf Coast and in the courts. From April to July of that year, engineers were scrambling to stop the hundreds of millions of gallons of crude being released into the Gulf of Mexico after the blowout preventer (BOP) on the rig failed to seal the pipe. Of course, major disasters are typically preceded by known, but uncorrected errors, and this was not the first time a company had trouble with isolation valves. As The Washington Post reported in June 2010, an operational integrity report written in 2001 covering the operations found that, “workers believe internal leak-through of isolation valves is a significant problem and under certain circumstances may pose a potential hazard to workers and equipment.”

Such incidents attract a lot of attention, but most leaks are well hidden somewhere deep inside the equipment and piping covering the grounds of a power plant. These valves gradually eat away at performance and profits, a problem that is particularly critical with severe service isolation valves (SSIV). These issues, though, are preventable by using properly designed valves that allow zero leakage. The problem is that “zero-leakage” does not always mean zero-leakage. The usual definition actually means acceptably slow leakage internally, with no visible external leakage. But by applying best available technology and adopting new standards, zero can equal zero, both internally and externally.

To protect people from injury and equipment from damage, it is essential to achieve zero-leakage with severe service isolation valves. Photo courtesy: ValvTechnologies

Slow Erosion

SSIVs are isolation valves that are used in high energy conditions at elevated temperatures, and pressures. They are used for numerous applications throughout power plants. These temperatures and pressures exceed the normal operational limits of thermoplastic seals, so the seal needs to be made by the metal components of the valve. There are also challenges the performance of commonly used and industry accepted hard facing materials utilized in high pressure and temperature valve seats. Further complicating the matter, the fluids involved may contain some solid content or abrasive materials that erode the seal surfaces, thereby producing leakage paths.

With SSIVs, the cost of the leakage is far greater than the cost of the valve. High temperatures and pressures coupled with erosive substances entrained in the fluid means that even minor leaks can grow into major ones. This results in unscheduled shutdowns and frequent equipment repair or replacement as well as wasted fuel/process liquids. To protect people from injury and equipment from damage, it is essential to achieve zero-leakage with SSIVs.

Like other valves, leakage can be either internal or external. It isn’t difficult to discover external leakage: you can see the cloud of steam escaping, for instance. Internal leaks, however, are entirely different. Take an isolation valve on a bypass line between the boiler and the steam turbine that redirects steam to the condenser. Any leakage though that SSIV lowers generator output while increasing fuel consumption. Since leakage is internal, it may only show up as a gradually increasing heat rate, requiring additional fuel expenditures and accompanying emissions remediation expenses to produce the same amount of electricity. The cost of replacing a faulty valve, on the other hand, is minimal compared to the lost output.

Keep in mind that there can be hundreds of SSIVs in a power plant. The overall losses are not from a single leaky valve, but the aggregate losses from each of them leaking a tiny amount. Together they add up to millions of BTUs never reaching the turbines. Zero-leakage SSIVs can typically improve a plant’s heat rate performance from 1-2 percent to as high as 3 percent.

Loss of Power and Profits

To understand the order of magnitude of the losses, consider an industry accepted value of 2 percent in heat rate (efficiency) loss attributable to cycle isolation or passing isolation valves and assume a 300 MWe steam turbine generator.

Class V valves should have a maximum seat leakage of 5 x 10-4 ml per minute of water per inch of seat diameter per psi differential. Photo courtesy: ValvTechnologies

Further assuming that this turbine generator operates 8000 hours per year at a round-the-clock average wholesale price of electricity of $50/MWh, the resulting loss in profit is $2.4 million per year.

While all valve losses ultimately affect the steam cycle efficiency, the overwhelming majority of the total loss will result from the high energy, sever services such as main steam or high pressure steam, hot reheat, cold reheat and the associated boiler or heat recovery steam generator sections. These high energy systems have the most impact on the output capacity.

Finally, by employing state-of-the-art valve seat leakage diagnostics, the target list of impactful valves can be reduced to the worst of the worst performers. Experience has repeatedly shown that the higher value targets yield paybacks on total replacement cost in the order of a couple of months or less. In any event, the cost of mitigating or eliminating valve leakage is tiny relative to the annual recurring losses which result from poorly performing valves in severe service.

The losses cited above may seem extreme at first glance, but is validated by other well-established research in areas such as leakage through an orifice in a pressurized pipeline, as well as heat and pressure losses in steam traps. Per the ANSI/FCI 70-2 leakage specification, a Class V valve should have a maximum seat leakage of 5 x 10-4 ml per minute of water per inch of seat diameter per psi differential (5 x 10-12 m³ per second of water per mm of seat diameter per bar differential). Buying Class V valves, therefore, would seem to eliminate the leakage losses. However, those standards apply only at the point of installation. Over time, the continuous steam leakage past the plug seat erodes the seal, causing steam cutting and wire drawing. What was once a Class V valve evolves into a Class IV, then Class III, Class II or worse. To try to seal against the high pressures (a two inch ANSI 4500 globe valve is subject to up to 19,623 pounds of force), a hammer-blow handwheel is sometime used. This method uses up to 10 times greater torque to drive the plug against the seat, but the method can damage the valve parts and won’t stop leakage through an eroded seal. Additional damage comes from vibration, flashing, cavitation and internal erosion.

Creating a New Standard

Just as utilities must apply Best Available Control Technologies to eliminate excess emissions, so should they adopt Best Available Isolation Technology (BAIT®) design features to eliminate the problem of erosion and gradually rising losses. Here, for example are some of the elements that make up BAIT® for ball valves:

• An integral seat: The integral seat is part of the valve body rather than a slip-in seat ring. A slip in provides a leak passage behind the seat, which doesn’t exist with an integral seat.
• High-strength Belleville seat springs: Belleville springs are cone shaped washers that apply a constant high thrust to create a mechanical preload on the ball and seat, and the packing. By stacking several of the washers, you can increase the deflection, while keeping the load on each washer constant. Use of Inconel 718 produces a high tensile strength (155,000 psi) with a high yield strength (125,000 psi) and high creep strength. This allows a seat spring compression of several hundred psi to fully position the ball against the seat, preventing ball misalignment or vibration and restricting particles from entering and damaging the seal.
• Full alignment/positioning of ball and seat
• RiTech® hard coating: RiTech® is a high-velocity oxygen fuel (HVOF) coating process that uses a hot, high-velocity gas jet to spray a coating of molten particles on to the ball and seat surfaces. Traditionally disks and seats of carbon, alloy or stainless steel are hardfaced, typically by welding on an overlay of Alloy 6, a cobalt-chromium which allows “excellent resistance to many forms of mechanical and chemical degradation over a wide temperature range, and retains a reasonable level of hardness up to 930°F (500°C)”. However, above 800°F, Alloy 6 becomes soft and subject to heavy wear and tear and galling of the valve seating surfaces. RiTech® 31 is both harder than Alloy 6 and maintains its hardness at high temperatures. At ambient temperature, RiTech® 31 has a Rockwell C hardness of 72, vs. 39.8 for Alloy 6. At 1400°F, RiTech® 31 has a Rockwell C hardness of 62, compared to just eight for Alloy 6. RiTech® 31 is also self-repairing in operation, so over 1,000,000 valve cycles are possible.
• Mate lapping of ball and seat: The ball and seat must be precisely mated to each other to form a perfect seal. This is accomplished by precision lapping the ball and integral seat for up to several hours on a rotating fixture. The final step involves using a three-micron diamond compound and moving the ball in a figure eight motion.
• Blowout-proof stem: a typical valve stem is externally inserted and uses a slip-on collar held in place by a pin. A blow-out proof stem is internally inserted and has an integral shoulder rather than a collar. Since it is internally retained, it is 100 percent blowout proof.

Adopting BAIT® makes it possible to actually achieve absolute zero-leakage on SSIV. Therefore, is it time for a new valve classification that goes beyond the FCI 70-2 Class VI standard? Introducing a “Class VII” would be zero-visible leakage for a minimum three minutes hydro test and gas test. It’s real, it is very achievable and is standard operating procedure for every valve manufactured at ValvTechnologies.

With this new standard, zero means zero, not something that we hope comes pretty close.

Author

Kevin Hunt is president of ValvTechnologies

Wind turbines are fitted with multiple bearings that each wear differently. Today, larger stresses in larger turbines are testing conventional bearing designs, particularly in mainshafts. Photo courtesy: Timken

With the growth of the U.S. wind industry and introduction of >1MW turbines, higher loads and increased stresses are impacting mainshaft and gearbox bearing life. Damage and failure modes are occurring sooner than expected, and for many wind farm operators, the cost of unexpected down tower repairs is adding up.

As a result, the industry is asking for longer life from mainshaft and gearbox bearings, and manufacturers are stepping up to bring solutions to the market.

“The operator will budget for one or maybe two major overhauls of the turbine over its lifecycle,” said Tony Fierro, application engineer for The Timken Company. “The challenge is that many turbines are requiring a major rebuild within the first seven to 10 years. This means higher O&M spending over the lifecycle of the turbine.”

Costly repairs

What is the financial impact to wind farm operators if a major rebuild is required every seven years? “If we assume the average life of a turbine is 30 years and the mainshaft and gearbox are being rebuilt every seven years, that means four rebuilds over the turbine lifecycle,” said Fierro. “With an upgraded bearing solution, operators can cut this number in half.”

For example, if a mainshaft and gearbox repair is $300,000 (crane costs included), this represents a total spend of $1.2 million over the lifecycle of the turbine. If these replacements can be cut in half, operators stand to save as much as $600,000 per turbine. For a typical farm operating 100 turbines, O&M savings can approach $60 million over 30 years.

Current design challenges

Modular wind turbine designs commonly use two-row spherical roller bearings (SRBs) to support and carry the mainshaft loads. In fact, SRBs dominate the modular turbine market in two different configurations; three- and four-point mount. These configurations are shown in Figure 1.

Three-point design

In the three-point design (left), the mainshaft is supported by the gearbox torque arms and a single SRB in front of the gearbox. This arrangement allows for:

• A shorter nacelle package and reduced turbine mass
• High system deflection and misalignment

While there are advantages to this design, including less nacelle weight and lower initial turbine costs, there are also distinct disadvantages with the two-row SRB mainshaft bearing, and with load transmission into the gearbox.

One issue is that the bearing must support a radial reaction and wind thrust loading on only the downwind (DW) row of rollers. Another problem is that, due to increasing internal clearance as the bearing wears, axial deflection and moment loads are transferred to the gearbox planetary carrier bearings. This additional loading can affect planetary gear meshes and thus, planetary gears and bearing loads.

Fig 1: Three-and Four-Point Mount Mainshaft Configurations

Four-point design

In a four-point design (right), the mainshaft is supported by the gearbox torque arms and two main bearings in front of the gearbox. These main bearings are often SRBs, but other arrangements including tapered and cylindrical roller bearings are also common. This arrangement allows for:

• A longer nacelle package and increased turbine mass
• Higher system stiffness
• Lower drive train deflection and misalignment

Main bearing performance is generally superior in four-point design turbines opposed to three-point, but some models still experience problems, particularly where an SRB is used in the rear position.

Fig 2: Early Stages of SRB Micropitting in a Turbine Mainshaft

Common failure modes

Micropitting

The use of a single SRB in the mainshaft position in MW-class turbines has shifted-once the preferred design, operators are now seeking a better solution. A primary driver is the premature damage seen on this type of bearing, mainly due to micropitting (surface fatigue). While there is not an official maximum limit, a conventional ratio of permissible thrust-to-radial loading deemed acceptable for a two-row SRB is approximately 25 percent.

In many large turbines today, actual thrust loads-as high as 60 percent in some instances-are significantly greater than this limit and concerns are increasing over issues related to unseating effects, abnormal load distribution between rows, roller skewing, retainer stress, excessive heat generation and roller smearing. With these high axial loads, only the downwind (DW) row of rollers supports both the radial and thrust loading. Frequently, the upwind (UW) row is completely unloaded creating a less than ideal operating condition.

As a result, mainshaft bearings in three-point mount turbines are experiencing the same common damage modes including micropitting, edge loading, roller end thrust, single piece cage failures, and cage and center guide ring wear as well as debris damage. This is leading to significant field failures early in the lifecycle of turbines.

Inadequate lubrication

Furthermore, mainshaft bearing operating conditions are typically not ideal for lubricant film generation. With a maximum operating speed of approximately 20 rpm, the bearing surface speed and lube film generation often are insufficient to keep the race asperities separated. In addition, changing pitch and yaw moments are constantly shifting the location and direction of the load zone-almost instantaneously. Thus, the formation and the quality of the lubricant film is interrupted.

For an SRB in a three-point mount turbine, this situation is accelerated. SRBs are operating under radial clearance, increasing the risk of micropitting or smearing. The early stages of wear are shown in Figure 2 where the distinct wear path in the DW row of rollers will eventually erode the designed contact geometry, leading to higher than predicted raceway stresses and eventually, bearing failure.

Bearing upgrades for existing turbines

Wear-resistant bearings

For a direct interchange to existing turbine fleets, Timken developed a Wear Resistant (WR) SRB that utilizes engineered surface technology in combination with enhanced surface finishes. The WR bearings protect raceways against micropitting by significantly reducing the shear stresses and asperity interactions. The engineered surface is a durable and unique tungsten carbide/amorphous hydrocarbon coating (WC/aC:H).

These coatings are two-to-three times harder than steel, one-to-two micrometers thick and have low friction coefficients when sliding against steel. With an advanced engineered surface on the roller, the coating is designed to polish and repair debris damaged raceways during operation. This enhanced surface finish also increases lubricant film thickness, meaning more efficient separation of the asperity contacts. Combined, these improvements reduce the shear stresses that cause wear. Additional features and benefits are summarized in Table 1.

A tapered solution

In working through the issues associated with SRBs, Timken engineers found a new answer for three-point mount turbines in a pre-loaded tapered roller bearing (TRB).

The bearing, having a one-piece double inner race and two single outer races, can be used at fixed positions on rotating shafts and is a direct replacement for OE mainshaft SRBs (utilizing the existing OE pillow block housing). Its design allows both rows of rollers to share radial and thrust loading equally, and minimizes loading into the gearbox because of the bearing’s ability to handle moderate misalignment (Figure 3).

In field trials, the Timken TRB demonstrated reduced wear, less deflection/load into the gearbox (without additional load to the torque arms) and increased system rigidity. The pre-loaded state of this high-capacity bearing helps to mitigate roller smearing/skidding and ensure load sharing across both rows, while tolerating more system misalignment than a tapered double-outer race bearing.

The design is contrasted to a two-row SRB solution in Figure 4.

Conclusion

As bearings perform their mission-critical function inside today’s MW-class turbines, dynamic and unpredictable stresses are causing untimely, expensive repairs. For the benefit of the wind industry moving forward, the reliability of mainshaft bearings must be improved. Market demand is driving the development of new solutions for retrofitting single SRBs in a three-point mount arrangement, including wear-resistant SRBs and a pre-loaded TRB design.

Author

Tony Fierro is an Application Engineer Specialist at The Timken Company.

The Fairmont Energy Station is a 25-MW project equipped with four Cat G16CM34 generator sets. The plant was commissioned in 2014. Photo courtesy: Caterpillar Inc.

In southern Minnesota, where wind turbines and ethanol plants are commonplace, two communities have turned to reciprocating engine technology to meet their future power generation needs.

The Fairmont Energy Station, a 25-MW project completed in 2014, and the Owatonna Energy Station, a 38-MW project now under construction, feature highly flexible, quick-starting, low-maintenance reciprocating engines suited for today’s market, which places a premium on rapid-cycling capabilities.

Minnesota is home to about 100 wind power projects and ranks No. 7 in net wind power production in the U.S. That means Minnesota power producers must have reliable backup power to fill the sudden gaps created by growing supplies of intermittent wind power. The $30 million Fairmont plant is well suited for the job, capable of reaching full capacity in just eight minutes. That’s significantly faster than power plants using the latest gas turbine technology.

“We required a more flexible and fast responding power source that could make up the difference,” said Peter Reinarts, manager of Generation and Operation at Southern Minnesota Municipal Power Agency (SMMPA), which owns the Fairmont and Owatonna plants.

SMMPA either purchases or operates more than 100 MW of wind power capacity. The four 16-cylinder gas-fired engines provided by Caterpillar for the Fairmont project work in sync with the association’s portfolio of wind power. “The generator sets can be promptly put on or offline to fill in the holes of the current wind generation,” Reinarts said. “These two assets aren’t at odds with each other, but instead work in a dynamic tandem.”

The intermittent nature of renewable generation, low-priced natural gas and advancements in engine technology and flexibility have given reciprocating engines new life in the U.S. as a competitive form of reliable generation. Reciprocating engines are becoming increasingly popular for utility-scale power projects.

Sky Global One, a 51-MW gas-fired plant about 70 miles west of Houston in the Rock Island community of Colorado County, began commercial operation in April 2016. The plant features six 8.6 MW Jenbacher J920 FleXtra gas engines from GE. Photo courtesy: GE

Gas engine power plants have several advantages over plants equipped with gas turbines. Perhaps the biggest advantage is flexibility.

Gas-engine power plants with multiple modular units are better at scaling their output across a wide range of incremental load without sacrificing efficiency. For example, 12 generator sets capable of generating up to 10 MW each can deliver output ranging from just a few MW to more than 100 MW in just minutes. By keeping a few units online, the other units can be deployed individually to offset sudden losses of wind power and bring balance to the grid.

“These new generator sets start quickly, like a car engine,” said Bruce Erickson, vice president of Ziegler Power Systems, which supplied the four Cat G16CM34 generator sets for the Fairmont project. “If the grid needs extra power 10 minutes from now – these generator sets can easily adjust to that need.”

In addition to speed and flexibility, gas-fired reciprocating engines can operate at part load – 25 percent or lower – without sacrificing fuel efficiency. Also, reciprocating engines have much lower maintenance costs versus the cost to maintain a sophisticated gas turbine. What’s more, the output of a modern-day reciprocating engine now exceeds 20 MW, up from 10 MW a decade ago. This has led to the development of more engine-based power plants exceeding a capacity of 200 MW worldwide.

Earlier this year, Sky Global One, a 51-MW gas-fired plant about 70 miles west of Houston in the Rock Island community of Colorado County, began commercial operation. The plant features six 8.6 MW Jenbacher J920 FleXtra gas engines from GE and will supply power to the 18,000 members of the San Bernard Electric Cooperative.

The plant can go from zero to full power in just five minutes, a useful feature in a state that leads the nation in wind power production. In addition to providing power on short notice, the power plant – and others like it – uses very little water.

“Reciprocating engines use no water as part of their cycle,” said Andreas M. Lippert, engineering leader for GE’s Distributed Power business. “Our Sky Global power plant in Texas basically uses no more water than an ordinary household.”

The J920 Flextra, a two-stage turbocharged engine, has a maximum output of 10.4 MW and can achieve electrical efficiencies of 49.1 percent at 50 hertz. The 60 hertz version has a capacity of 9.35 MW and can achieve electrical efficiencies of 49.9 percent. The two-stage turbocharging means the J920 can achieve a fuel efficiency rating of more than 90 percent when used in a combined heat and power (CHP) plant that produces hot water, GE said.

GE recently received an order for two 9.5 MW J920 FleXtra gas engines in Italy. The two units will be used in a district heating repowering project in Rome. Once the project is completed, the new 19-MW power plant will provide power to about 50,000 residential customers in Rome.

“This project showcases the advantages of our J920 FleXtra gas engine technology,” Lippert said, “as more European utilities and municipalities modernize their CHP plants with more efficient, reliable and flexible gas engines to meet increasingly stringent environmental regulations and support the growth of renewable energy on the grid.”

Construction of the plant is expected to begin in 2016 and finish in 2017. In addition, GE has also received orders for several cogeneration projects in Germany.

The Rubart Station, a 110-MW gas-fired power plant featuring 12 Caterpillar G20CM34 generator sets in southwest Kansas, is another example of how reciprocating engines are meeting demands for highly flexible generation systems that can accommodate the fluctuations of renewable power. The plant is capable of reaching full power in less than nine minutes and can generate a wide range of output.

“The facility can produce 10 MW, 110 MW or anything in between without losing efficiency, and that’s an enormous advantage for us,” said Kyle Nelson, senior vice president and chief operating officer at Mid-Kansas Electric Co., the plant’s owner.

Kansas has more than 3,800 MW of installed wind power capacity and is leading the nation in new wind power projects. In the second quarter, Kansas led the nation in new construction announcements at 778 MW, according a report issued last month by the American Wind Energy Association (AWEA). Nationwide, more than 18,000 MW of wind power capacity are under construction or in some advanced stage of development, according to AWEA.

Luckily, the Rubart Station is permitted to double its capacity. The site was built with enough space to add 12 more engines, if more capacity is needed. Rubart is the largest gas-fired power plant ever built by Caterpillar.

Aggreko is a leading provider of temporary power worldwide. The company uses reciprocating engines to provide power for special events, emergencies, and extended projects. Photo courtesy: Aggreko

Aggreko is a leading provider of temporary power worldwide. The company uses reciprocating engines to provide power for special events, emergencies, and extended projects. It provides comprehensive power generation services, including the engineering, installation and operation of temporary power systems with wide ranging capacities.

Frank Pizzileo, business development manager at Aggreko, said reciprocating engine technology and the market for reciprocating engines are vastly different than a decade ago. Emissions are 16 times lower, engine efficiencies range from 38 to 50 percent, maintenance is simpler, and the price of natural gas is a lot cheaper.

“The technology has come a long way. It’s primarily driven by the need to reduce emissions,” Pizzileo said. “They’re much more tolerant to load swings. You don’t see as much of a derate for higher ambient temperatures and altitudes that you would see in a turbine.”

Financially, a small to mid-size power plant equipped with high-output reciprocating engines can effectively compete against a gas-turbine plant of the same size, Pizzileo said. “For the right application, I bet the project IRR utilizing recips would look pretty good or better.”

Engine efficiency ratings are now comparable to efficiency ratings for gas turbines, he said. Best of all, reciprocating engines are significantly cheaper.

“A 1-megawatt turbine would cost three times as much as a recip engine of the same size,” Pizzileo said. “For us, it is certainly the product of choice for what we bring to the market.”

Power producers are turning to reciprocating engines for a variety of reasons, from providing backup power for intermittent renewable resources on short notice to reducing nitrogen oxide (NOx) emissions for compliance with new federal emission limits.

They have been deemed to be an efficient solution for commercial and industrial CHP systems and grid operators struggling to balance supply and demand.

But the biggest factor behind the increasing use of reciprocating engines for CHP applications is the prospect for low natural gas prices. According to the Department of Energy, natural gas prices are expected to rise over the next two years but will remain low enough to incentivize the continued construction of gas-fired plants in the U.S. Natural gas prices are expected to average $2.36 per million Btu (MMBtu) in 2016 and $2.95 per MMBtu in 2017. In 2006, the wellhead price of natural gas in the U.S. averaged $6.42 per MMBtu.

“It’s a different dynamic,” Pizzileo said.

Recovering heat and water from flue gas can reduce water usage and boost power plant performance. The National Energy Technology Laboratory has tested a promising technology that condenses water and recovers heat from flue gas.

The image of billowing clouds of condensing water flowing from the stack and cooling towers is how many Americans picture thermoelectric power plants, but they may not know that plume abatement towers can be used to capture the water from the cooling towers. Escaping flue gas contains heat and water that is generally considered a waste stream that is lost to the atmosphere, but if it could be recovered and reused, it could hold the potential to lower plant water usage and increase plant efficiency.

The U.S. Department of Energy’s (DOE) National Energy Technology Laboratory (NETL) supports several projects that are developing ways to lessen the amount and impact of water usage at thermoelectric power plants, including condensing water from cooling towers and flue gas. Three basic methods can be used to recover water: condensing heat exchangers, membranes, and desiccants. NETL helped commercialize a condensing heat exchanger for cooling towers, the SPX plume abatement cooling tower ClearSky, which captures an average of 18 percent of the water evaporated from a cooling tower. Flue gas loses less water overall to the atmosphere, but does have a high heat content that may be recovered.

Until now, there has been no practical commercial technology available for recovering both waste heat and water from the power plant flue gas. Heat is removed from the flue gas through the use of economizers and air preheaters, but condensing water (and acid gas) is a limitation in how low the temperature can be taken. Condensing flue gas moisture by simply removing heat in a heat exchanger is a problem because a large surface area is required and equipment corrosion often occurs because of the acidic condensate. The recovered water needs further treatment before it can be used for any other processes due to the high acidity and other contaminates that may present in the water.

TMC Design

NETL has partnered with Gas Technology Institute (GTI) and Media & Process Technology Inc. (MPT) who have developed a nanoporous ceramic membrane device that condenses water and recovers heat from flue gas. The innovation is called the Transport Membrane Condenser (TMC). The TMC has been tested in various boilers and configurations and has been shown to be effective at heat and water recovery. The technology can be particularly beneficial for coal‐fired power plants that use high‐moisture coals and/or a wet flue gas desulfurization (FGD) for flue gas cleanup.

The TMC is constructed from a ceramic membrane that is heat and chemical resistant. The unit consists of tubes of alumina that are partially fired to give high porosity. These tubes are coated with another layer of alumina to form an intermediate layer with smaller pore sizes, then a final very thin coating of Zirconium dioxide (ZrO2).

The intermediate layer is made of distinct particle sizes that can be controlled to give well-defined nano-size membrane pores, and the final coating makes the outside tube surface smooth and slippery to prevent particulate fouling. The tubes are bundled into a shell to form essentially a nanoporous heat exchanger. In the case of flue gas water recovery, the membrane tube spacing is optimized to fit into the flue gas duct with minimal flue gas side pressure drop and maximum membrane tube surface area for heat and mass transfer.

Flue gas flows through the duct and comes into contact with TMC tubes. Water vapor condenses in the pores of the membrane tubes and passes into the inside of the tubes, which have water flowing through them. Non-condensable gases such as CO₂, O2, NOX, and SO₂ are inhibited from passing through the membrane by the condensed water clogging the tube membrane pores. The low pressure difference across the membrane tube wall and its nanoporous membrane coating on the tubes inhibits particulates from clogging the pores. The recovered water is of high quality and mineral free, and therefore can be used directly as boiler makeup water, as well as for other processes.

TMC Function

For a coal‐fired power plant boiler equipped with a wet FGD unit, flue gas exits at up to about 180 °F, with nearly 100 percent relative humidity. It contains up to about 40 percent, in volume, of water vapor. For coal‐fired power plant boilers with a dry FGD, the flue gas moisture content is still comparable with the industrial gas‐fired boiler flue gases, with a dew point at 130 to 140 °F, or about 20 percent in volume of water vapor in the flue gas stream. If 40 to 60 percent of this water vapor and its latent heat could be recovered and reused, the plant thermal efficiency could be significantly improved while providing a water recovery benefit.

The current project for power plant application is aimed at optimizing heat and water recovery in a two‐stage TMC design. For the first stage, the TMC will use condensed steam from the steam turbine in the tubes. The condensed steam is typically at 90°F to 110°F, which is sufficiently cool to provide a driving force for water transport across the membrane. The recovered water and heat are entered back into the steam cycle downstream of the first low-pressure feedwater heater, thus requiring less steam to heat. Calculated efficiency improvement is about 0.7-0.8 percent.

The amount of water and heat collected this way is limited by the amount of make-up water required for power plant boilers, which is typically about 2 percent. Research is underway to increase the amount of heat recovered from the flue gas. For the second stage, the TMC will recover a larger part of water from the flue gas and add it into the plant cooling water stream. This portion of recovered water can replace part of the cooling tower water makeup, or it can be used in other processes of the power plant.

Past Project Successes

• Industrial Steam Boilers were outfitted with TMC modules to form a TMC unit with controls. Boiler fresh makeup water (typically 10 percent to 50 percent of the boiler feedwater flow rate) was used in the TMC unit to recover flue gas water vapor and heat. The preheated makeup water coming out of the TMC requires less fuel from the boiler, therefore, the boiler efficiency can be improved by 5-10 percent depending on the boiler makeup water requirement. At the same time, the boiler makeup water amount was also reduced due to water vapor recovery from the flue gas. Advanced TMC-based heat recovery systems for industrial, large commercial, and institutional boilers have been made commercially available by Cannon Boiler Works as the Ultramizer® product. Current sizes include 10-20 MMBtu/hr units operating at 92-95 percent efficiency with ongoing developments to scale up to larger sizes of over 20 MMBtu/hr.
• Laundry Steam Tunnels were equipped with TMC units on top of their stacks to recover the unused steam, which were used for preheating the hot water to be used in the washing machine. This saved water and steam requirement from a steam boiler leading to cost reductions for plant operations.
• A Coal Power Plant was equipped with a pilot TMC unit for slip stream testing with five-week continuous operation and has produced good heat and water recovery results.
• Home Heating Systems were outfitted with a similar waste heat and water recovery system, however, the water vapor condensed in the tube membrane pores is re-evaporated into the furnace circulating air stream. The preheated circulating air with added water vapor can not only improve the furnace efficiency but also raise the air humidity level, thus providing home occupants a comfortable home environment. In this configuration it is called the Transport Membrane Humidifier (TMH) and can raise the efficiency of a standard mid-efficiency furnace by about 15 percent. This version of TMH can be used for existing low to mid-efficiency furnace retrofit applications, which account for more than 50 percent of current installed furnace population. A TMH module can be also integrated into a high-efficiency furnace to provide air humidification with some efficiency improvement. Besides maintaining a lower pressure at the flue gas side inside the TMH, a pressure switch is also used to ensure that no combustion gases can enter into the circulating air stream through the TMH.

Building on these successes, another NETL-managed project with GTI and MPT will develop and test a high-pressure modular version of the TMC in GTI’s pilot-scale pressurized coal combustor. The project will evaluate its performance and analyze the results for future commercial-scale pressurized oxy-combustion power plants. Testing over the next year will culminate in a scale-up and integration evaluation for a commercial-scale power plant at the end of next summer.

Input from utility equipment suppliers and industry groups will be solicited to guide the commercialization efforts to meet the needs of utility customers.

Because cost is a significant challenge associated with the technology, ongoing work is focused on improving the performance of the TMC by increasing the water flux and lowering the manufacturing cost of the membrane and integrating it in the boiler at various stages of the thermoelectric power plant.

The most promising applications are downstream of a FGD where flue gas water content is high and inlet temperature relatively low. Another possible application is for a Natural Gas Combined Cycle (NGCC) plant with a fired heat recovery steam generator (HRSG).

A Different Approach to Water Usage and Treatment Challenges

Energy and water are both becoming more constrained and it is a challenge to use both more wisely as population and demand increases.

The interconnectedness of energy and water has been realized. Tremendous amounts of cooling water are needed for condensing steam in the thermoelectric Rankine cycle to produce electricity, and large amounts of energy are typically required to transport and treat water. The DOE initiative to meet this challenge is called the Water-Energy Nexus, and power plants represent a promising opportunity to exploit synergies among water and energy systems.

Challenges to more widespread use of this technology are the current low cost of energy and water. Even with these low prices, several applications of the TMC, such as industrial boilers and laundry operations, are already cost competitive with a relatively quick return on investment of less than two years.

However, it is difficult to achieve widespread adoption of this energy and water saving technology.

Power plants will have similar challenges, but if the TMC is commercialized, thick clouds of condensing water exiting a power plant stack will become a less common site at thermoelectric power plants because the majority of the water and heat that create them will no longer escape into the atmosphere. Instead, they will be used to reduce water consumption, increase plant efficiency, and potentially lower costs.

Author

Barbara Carney is project manager with the U.S. Department of Energy’s National Energy Technology Laboratory

Mobile digital solutions for the industrial internet offered by companies like ABB and GE, and further leveraged using cloud technologies like Microsoft’s Azure platform, are changing the way the power industry manages day-to-day plant operations on the go.

Photo courtesy: ABB

By Tim Miser, Associate Editor

Italy, 1952. The war is finally over, and people are beginning to hope for the future again. Soldiers are starting families; towns are being rebuilt, and at long last life is beginning to look pretty good. The mind naturally wanders to cobbled streets filled with well-dressed Torinesi. Here a Vespa whizzes sveltely by. There a mother steps out of a shop with the day’s bread under her arm. Sure, it’s stereotype-or more accurately archetype-but it’s a powerful cultural meme nonetheless. In many ways, those black-and-white days are a different universe, unknown to us now. The past is a foreign country, as they say.

So it was when GE was called on to help build a power plant in Chivasso, a few miles northeast of Turin in Northern Italy. Back then, computers remained mostly exotic myth. Integrated circuits existed in infancy, but had not yet supplanted point-to-point wiring in the real world. Silicon? What was silicon? Relative to today’s technology, GE had a more rudimentary toolbox to work with. But it had a real opportunity to take a step into the modern world, indeed to play a role in creating that world. And that’s just what it did. The project would be the first time GE had installed a steam turbine in Italy. The plant was commissioned soon after, and served the surrounding area for decades.

But this is not a fairy tale. Fast forward sixty-some years, and the Chivasso plant was in trouble. Actually things were worse than that. In 2013, plant owner A2A had to mothball the facility entirely. The influx of renewable energy onto the grid, combined with conventional generation and a high-voltage cable from France, had created more power than the region could absorb. The conventional Chivasso plant could not respond quickly enough to changing grid demands. If it was to survive, it needed to change the way it did business.

GE had a plan. Mario Cincotta is general manager of multi-year agreements for GE’s Power Services business in Europe. He and his team analyzed the local energy ecosystem and decided to upgrade the plant’s natural gas-fired turbines with new technology and new software. At first they got bad news. Data mining exercises revealed that a brand new plant using Siemens hardware nearby would be able to out-compete them. But when the team deployed GE’s Asset Performance Management software, leveraging the cloud-based Predix platform for the Industrial Internet, the situation began to look more encouraging. After a lot of hard work, they were able to decrease the facility’s start-stop times by 2.5 fold. That speed was critical to helping the plant meet market demand, ramping up quickly to capitalize on profit opportunities when the wind stopped blowing and the grid demanded power.

They also installed a new type of combustor on the plant’s 9FA gas-fired turbines. “The technology turned an airplane into a space shuttle,” says Cincotta, “but now we needed the data and software to drive it. Without them, the power plant would be just a fancy toy.” The GE team input data from sensors inside the turbine into software applications, which allowed them to more efficiently harness the machinery’s capabilities. Using GE software, the Chivasso plant was able to manage the complex data generated during the facility’s operation. “Otherwise it’s a nightmare,” says Cincotta. “Like manually flying a spaceship.”

The Digital Transformation

A modern gas-fired power plant is equipped with more than 10,000 sensors. They measure and communicate movement, vibration, temperature, humidity, and chemical changes in the air and water. Historically, only a fraction of this data has been analyzed and quantified in the day-to-day operation and maintenance of a facility. The digital transformation of power generation has begun to change this, creating opportunities to exploit data and make sense of information that would otherwise go to waste. This allows power plants to trim costs, increase sales, and boost efficiency and reliability. “Big data” it’s called, and it’s a world where analytics rule.

GE worked with A2A to rescue the Chivasso Station power plant from closure. With the introduction of digital controls on existing assets, the facility was able to decrease start-top times by 2.5 fold and serve power to a highly dynamic grid in a competitive manner.

Power plant digitalization isn’t a new idea, of course, but momentum in the field is picking up. Thanks to economies of scale, prices to deploy digital infrastructure are dropping, and the technology itself is growing ever more intelligent.

Niloy Sanyal is the Chief Marketing Officer for Power Digital Solutions at GE. He puts it like this: “Now that expenses associated with digitalization are coming down dramatically, we can leverage data much the same way that the consumer internet has been leveraged. So just as book purchases on Amazon or map queries on Google now leverage big data, so too can power plant infrastructure, only with greater complexity.”

In a letter to shareholders last year, GE CEO Jeffrey Immelt said, “In the Industrial Internet we see the next great wave of productivity-both for our company and for the customers we serve. We are a company that invests in broad industrial transitions, and they don’t come much bigger than the full application of data and analytics to machines and systems.”

Sanyal agrees: “We are at a tipping point where technology is concerned. With the advent of big data and the cloud, we finally have an inflection of technologies that allows us to make massive computations and algorithmic deductions better than ever before.”

Seeing enormous opportunity on the horizon, multiple companies have developed digital solutions for the industry. Oracle is in the market, and Microsoft recently partnered with GE to bring the industrial internet to its Azure cloud for industry. ABB has also positioned itself as a leader in digitalization.

“Digitalization of the power industry answers a need that is critically important,” says Thomas Trepanier, Senior Vice President of the Enterprise Software product group at ABB. “We need to share information more effectively-between engineering and maintenance staff, business and operations, and other workgroups. When the right information is available at the right time, work gets done.”

Trepanier notes that the use of digital tools like enterprise asset management software, operations tools, and equipment reliability software can help power plants significantly decrease waste at their facilities and increase “wrench time” for maintenance, operations, and engineering. “When you have quality data with good communication between software tools and the workforce,” he says, “the result is enhanced safety, increased reliability, and a significant decrease in unexpected failure.” This allows for higher capacity factors and operational excellence, he says.

Missed Opportunities

In the past, power plants incurred costs and performance penalties because they could not deliver the right information to the right people at the right time. “The manual paper-based process created silos of information that were difficult to break out of,” says Trepanier. Such communication failures led to major component failures in transformers, large pumps, and other critical equipment, he explains.

GE offers software controls for digital power plant assets organized into six portfolios, ranging from nuts-and-bolts operations management to business strategy development. Photo courtesy: GE

The problem of poor communication is further exacerbated by the fast pace at which the industry must now operate, Sanyal explains. The increased penetration of renewables means power plants have to be more flexible than ever before. Loads now fluctuate dramatically, and facilities must dispatch frequently. Plants that used to operate as slow and steady base-load facilities must now assume a much different posture.

Digitalization gives a plant’s staff a better chance to analyze the information and predict failures before they happen, says Trepanier. “Tools like those offered by ABB bring more efficiency to the work cycle,” he explains. “They do this through capabilities like electronic work packages, which enable assets to be taken out of service and put back into service more quickly, lowering out-of-service time and increasing efficiency of work planning and maintenance processes.” According to analysis performed by ABB partner DataGlance and validated by power producers in the industry, enhanced efficiency tied to ABB’s software applications can lead to expected cost savings for a power plant of approximately $2.7 million per year, Trepanier says.

“Digitalization also benefits distributed power involving assets like Jenbacher engines,” adds Sanyal. “Resources like these can be brought to the grid much better with the aid of digital technologies. So customers like hospitals and manufacturing facilities that generate their own power can use software to integrate to the grid much more effectively, and in a more efficient and automated way.

The Business Case for Digitalization

Nothing in the power generation industry is inexpensive. Between the never-ending struggle to comply with environmental regulations and the constant costs of maintenance and operations at a facility, plant stakeholders could be forgiven if they tired of spending money. Still, the case for investing in plant digitalization is a strong one. Indeed, it is because of the enormous capital expenditures required by the industry that it becomes so important to wring every last drop of productivity from power assets, and software is indispensable in this effort.

“If I’m the manager of a combined-cycle gas turbine plant,” says Sanyal, “digital solutions give me real-time insights into my operation. Using tools that are common between the trader, dispatcher, and plant manager lets me know the exact capability of any given asset at any point in time, and this helps me make money.”

Trading strategies can be aligned with digital information, he explains, and this helps plants dispatch assets more profitably. “You don’t have to do hardware upgrades. You don’t have to do services upgrades,” he says. “It’s a solution that bridges both trading and asset teams and helps them make better collaborative decisions. Customers can see up to 5 percent more revenue with no additional cost than the software itself.”

Trepanier concurs. “As digitalization of power plants makes more information available to personnel from the plant floor to the boardroom,” he says, “day-to-day operations will not be the only activities that are enhanced.” The ability to make critical business decisions that affect planning for the coming days, weeks, months, and even years will be improved, he explains, and this will result in a more productive and successful enterprise overall.

Additionally, he says, mobility will be a driving force in efficiency for workers in the plant, greatly enhancing work management processes. The ability to download the information required to perform inspections and rounds anywhere in the plant will enhance both safety and reliability. And, because these workers will be able to send pictures, audio, and video from the field to critical decision makers in real time, the entire enterprise will be more productive as everyone works from the same high-quality information.

The Technologies

Many companies have developed products for the expanding market growing up around digital power plants.

ABB offers an Asset Suite that provides enterprise and work management capabilities specifically designed for power generation, transmission, and distribution organizations. This suite of applications standardizes and streamlines work processes to maximize productivity and improve asset performance through increased availability and improved reliability. The company also offers an ER Suite, among many others, that includes separately licensed modules for template-based maintenance and reliability optimization, system health, component health, and lifecycle planning.

GE offers digital solutions for all types of power generation, from renewables like wind, solar, and hydro, to more conventional fossil-fired assets and nuclear installations. The technology can be deployed in both GE hardware and in competitor’s hardware alike. “We’ve had lots of success stories with Exelon and Saudi Electric that have deployed our software in competitor’s hardware,” says Sanyal.

GE offers six different product portfolios, most representing suites which are comprised of multiple component applications. Portfolios include: Asset Performance Management, Operations Optimization, Business Optimization, Advanced Controls, Cyber Solutions, and the Predix Platform.

Sanyal explains that GE’s Predix is a licensed platform which allows IT departments or third-party developers to create applications on their own, which can then be deployed in the Predix environment for use at power plants. “We’re excited about it,” he says. “Five years from now there will be thousands of apps in use. Customers, third party developers, even competitors will begin to converge on a common platform. This ecosystem is critical. In the long run it will differentiate competitors and determine the winners and the losers.”

Researchers experimenting with the storage of carbon dioxide (CO₂) emissions from the Hellisheidi power plant in Iceland stumbled upon a phenomenon that could lead to meaningful reductions in greenhouse gas emissions from power plants.

According to a study published in June in the journal Science, a team of scientists and engineers from Columbia University, the Universities of Copenhagen and Iceland, and Reykjavik Energy (the plant’s operator) successfully converted CO₂ into solid rock in just two years. Assuming the process would take centuries to achieve, researchers were shocked.

The results “just blew us away,” Martin Stute, the study’s co-author, told the Los Angeles Times.

Under the right conditions, though, the conversion can occur in just months, the study found.

Researchers injected 175 tons of pure carbon dioxide and later mixed it with hydrogen sulfide and water. The carbon dissolves amid the extreme water pressure, the study showed. The mixture was then pumped deeper into a layer of basaltic rock, where the mixture mineralized into stable carbonate within two years, the study found. The process is known as CarbFix.

“The results of this study demonstrate that nearly complete in situ CO₂ mineralization in basaltic rocks can occur in less than 2 years,” the authors wrote. “Once stored within carbonate minerals, the leakage risk is eliminated and any monitoring program of the storage site can be significantly reduced, thus enhancing storage security and potentially public acceptance.”

The Thermal Ceramics business of Morgan Advanced Materials announces the availability of its WDS UltraShell microporous insulation, whose superior insulating properties make it ideal for energy sector applications demanding hot piping, including power plants, refineries, and renewable energy facilities. Morgan’s Porextherm WDS UltraShell solution enables the construction of smaller, lighter, and more cost-effective double wall “pipe in pipe” hot piping applications.

WDS UltraShell insulation offers the low thermal conductivity needed in hot piping applications to ensure that materials inside are insulated from ambient conditions, in addition to protecting workers from burns due to contact with non-insulated hot piping. The superior insulating properties of WDS UltraShell insulation ensure that the temperature of the product within the piping remains as constant as possible while minimizing the pipes’ outside diameter and thickness. Constructed from fumed silica and other inorganic silicates that act as opacifiers for minimizing infrared radiation, the core material of the WDS Ultra is not flammable and meets the requirements of ASTM E84 with Smoke/Flame Spread rating 0/0 (US) and DIN ISO 4102 for fire protection class A1 (EU).

Morgan Advanced Materials
Info http://powereng.hotims.com RS#: 200

Meter Circuit Accuracy Tester

TESCO is pleased to introduce the CT Ratio/Burden Tester (Catalog No. 1047).

TESCO’s new CT Ratio/Burden Tester is a lightweight, portable and highly accurate in-service test set to assist in testing the accuracy of your meter circuits. The CT Ratio/Burden Tester can help determine if there are installations errors, loose connections, incorrect ratios, resistance buildup, open CT’s, or manufacturers defects.

The CT Ratio/Burden Tester measures and displays the primary and secondary current of the CT under test, and the ratio of the currents. All test data is stored in the internal memory and easily uploaded to a PC or bluetooth device.

TESCO
Info http://powereng.hotims.com RS#: 202

There are about 7,304 operational power plants in the United States utilizing diverse technologies such as gas, coal, wind, solar, hydro and nuclear. All of these power facilities ultimately support 124 million households.

Reliability and safety are key drivers for power plant operators. Having just spent a week in India, I found that most locals are accustomed to disruptions in service. In fact, we experienced outages on almost a daily basis.

I’d like to take this opportunity to lead a brief dive into nuclear power. As you may know, there are 438 nuclear plants in operation around the world, 61 of which are located in the U.S. Nuclear power has been part of the grid since 1954.

We are all familiar with the three biggest nuclear accidents: Three Mile Island in 1979; Chernobyl in 1986; and Fukushima in 2011. Unfortunately, there have been at least 99 accidents since 1954 that resulted in loss of life or damages in excess of $50,000. Since the Fukushima incident, a 12-mile exclusion zone circles the power plant and people have limited access to the site. Ultimately, 50,000 households and 156,000 people were permanently displaced.

An NRC task force investigated the Fukushima incident and ultimately concluded that current operating standards “do not pose an imminent risk to public safety and health,” which to me is a roundabout way of saying “we doing it right.” However, the task force did pull together a list of over 10 new recommendations as a result of Fukushima. Some of those include strengthening defenses against flooding and earthquakes, and hardening vents that carry away hydrogen gas from damaged reactor cores. Backup electric power for extending plant’s capabilities to project reactors and spent fuel was another of the recommendations that was a result of this investigation.

Highlighting the worst nuclear incident in 25 years illustrates the worldwide commitment to safe, responsible generation. Operators use advanced equipment to monitor their reactors 24 hours a day. Located in Illinois, for example, the Dresden Generating Station has been in continuous operation since 1960. Its first unit, Dresden 1, was retired in 1978. Units 2 and 3 — two GE BWR-3 reactors — have been in operation since 1970. This plant safely generates power for over one million households. Its staff have taken reactors offline as necessary when, for example, it detects elevated water levels in a reactor.

The U.S. Nuclear Regulatory Commission provides regulatory oversight for plants like Dresden. This framework has three major pillars: Reactor Safety; Radiation Safety and Safeguards. Key staff are rigorously trained in segments that include initiating events, mitigating systems, barrier integrity, emergency preparedness, public radiation safety, occupational radiation safety, and physical protection.

There are currently more than 15 applications for new nuclear power facilities. Proposed sites are in Texas, Florida, New Jersey, North Carolina and other states. The last newly built reactor in the U.S. came online in 1996. The next reactor, Watts Bar 2, entered service in mid-2016 in Tennessee. This $4.7 billion unit has undergone several design modifications, all of which were spurred by the Fukushima incident.

We predict the commissioning of more nuclear power plants in the United States over the next 20 years. Currently nuclear accounts for 20 percent of all U.S. generation, the third highest source. Coal, the top source, generates 40 percent of our power, but is projected to decrease over the next 20 years. Safety training will continue to play a key role in the nuclear sector to ensure adherence to protocols and regulations that have that been in place for over 50 years. In addition to the onsite training that the power companies provide, the NRC provides an ongoing list of training courses on topics that include environmental monitoring and materials control and security systems.

Akshay Patwal

Timot Veer

Digitalization is transforming the energy industry, providing new insights into power plant operations and uncovering hidden opportunities to boost performance and availability. Traditionally, much of the data generated within power plants was limited to remote diagnostic and monitoring services, primarily analyzing data for monitoring turbine operations. By adding new data sources and analytical capabilities, particularly in service and operations of power plants, new avenues are opening to greater understanding of customers’ business needs and the behavior of power assets.

Tremendous new possibilities for data utilization have lately emerged, providing novel business models to customers, tailored to meet their specific needs for operational flexibility and maintenance optimization. A solid approach goes beyond simply collecting the data or providing a standalone software program. It integrates valuable, insight-driven analytics with field service data, global fleet performance data, and other diverse data sources to optimize plant performance. Siemens’ digital services offerings are already yielding concrete results and paving the way for power plant owners and operators to obtain a more informed and judicious decision-making framework to support plant operations. This results in higher availability and improved predictability of asset performance for power plant owners/operators, with the ultimate goal being a positive impact on the bottom line.

Digital Transformation

Digitalization is about more than introducing advanced sensors, collecting big data, and developing powerful software. Digitalization changes how we interact and do business in a holistic way. The most important thing in this transformation is to foster a change in culture and mindset, enabling both the vendor and the customer to evolve in progressive thinking about ‘digital services’.

Siemens’ portfolio of data-driven services is called Digital Services for Energy, powered by Sinalytics. Traditional servicing of plant equipment still exists. However, now effective management of data and context-based analytics, coupled with domain expertise, is supplementing traditional services. The business insights and revelations gained in this effort enable a prescriptive approach to offer customers more operational flexibility and enhanced risk mitigation.

Sinalytics Platform Architecture

To implement an effective data management and analytics framework for digital services, a scalable, industrial-strength analytics platform architecture is necessary to leverage data across a company. The Sinalytics platform architecture is a hybrid infrastructure comprising both cloud-based and on-premise instances to provide value to customers by exchanging and interpreting data, reports, and other information, as well as to support internal process improvements and knowledge engineering. Access to applications, data, and various visualizations or reporting becomes streamlined, and complex information for decision-support is provided at one’s fingertips.

Data transfer to Sinalytics relies on highly secure and scalable data acquisition, and transfer solutions used across multiple industries. The Sinalytics platform architecture is designed to work with structured and unstructured data, including machine-operating data, performance data, field service and repair data, and various third-party data sources. One core feature is the generalized and comprehensive data-model, as well as internal interfaces allowing business users scalable and standardized access to develop and utilize analytical applications.

Data analytics plays an important role in empowering customers by providing the right decision-making tools for the present, and a forward-thinking vision for operations and maintenance scenarios. Advanced statistical algorithms and pioneering machine-learning capabilities are used to generate predictive maintenance and performance optimization business applications. The progression from descriptive to predictive or prescriptive, complemented by extensive domain expertise and fleet operations experience, offers competencies to optimize system operations, improve flexibility on performing maintenance, and positively impactthe bottom line.

Advanced data analytics offers the capability to render a ‘digital twin’ of all assets, laying the foundation for improved operations optimization, higher plant performance, and an improved revenue model at the plant and fleet level.

For better or worse, we live in an era of instantaneous communication. As soon as a power outage, spill, or merger happens, the whole worlds seems to know about it. Where good information is not available, poor information will flood into that void, and fill it quickly. This is true in the case of crisis or bad press, and it is true in the sharing of good news, in promotion and in brand management.

In this rapid-communications climate, it is increasingly important that companies have a communications plan capable of responding capably, quickly, and consistently, both when the seas are tranquil and when storms are raging. Here are five key steps every company should consider in developing an effective communications strategy:

1. Plan ahead.

Information is instantaneous. It is not possible to both plan and respond. Companies must think ahead to assess potentially relevant issues, controversies and communications challenges, at each step considering the likely interested audience and the most effective potential team to engage. When the time comes, communication must be both purposeful and consistent in order to be effective. That is impossible without planning.

2. Build an effective team.

Communication needs will direct the demands for the team. Identify your roles and resources, considering your message and audience. High-profile matters with significant news-media involvement may require both media monitoring and a spokesperson. Statements related to litigation will demand legal review.

Don’t overlook website management and social media. Electronic communications allow for faster response and broad outreach, but can be challenging to oversee and are quickly out of date. These tools demand a designated team member for oversight and updates.

Develop and adjust your team to respond to changing demands.

3. Understand the audience.

Know who cares and why. It goes without saying that a crisis-communications plan places different demands on a team compared with a new product roll-out. But the audiences for even these divergent issues will likely overlap.

Think of your team members as your de facto first audience. Employees are a great source of monitoring and audience assessment, and they likely will serve as a key point of your outreach and response team.

Looking to the external audience, ask if you are communicating with the public at large, or with a more narrow target audience. Differing audiences demand different approaches and means of sharing information. Once you have identified your interested audience(s), you can better assess how to build relationships with interested parties.

4. Understand the issues

Know the issues you face, the facts you need to share, and their implications. There is no substitute for detailed knowledge of the subject about which you are communicating. Every newsroom editor knows that when a reporter’s writing is vague, murky and unintelligible, there is a good chance that the reporter does not know enough about the subject to explain it clearly– and therefore needs to do more factual investigation before attempting to “write around” the problem.

Knowing your subject will allow you to communicate confidently, authoritatively, and in detailed terms rather than in platitudes or generalities. Aim to be the go-to source of useful, reliable, and accurate information for your intended audience.

5. Enforce team’s roles, responsibilities and LIMITS.

Communicate expectations and then enforce them. Consistency is key to effective communication and every team member must be responsible for their role. Public affairs are unpredictable enough without unwelcome “surprise” communications coming from one’s own team-especially if those statements are potentially damaging or inaccurate.

Know and communicate limitations. For litigation and compliance issues, the team must understand the role of legal review and expectations for communications – before the communication occurs.

In summary, a strong communications team is the result of careful planning. When the team is functioning properly, there are no “surprises” and all team members understand their roles. Although your team may never be able to tame the constant news cycle or the churning sea of social media, you will have a solid structure capable of navigating the waters of public opinion and delivering your message safely to shore.