Federal regulation of interstate gas transmission in the United States is regulated by the Federal Energy Regulatory Commission (FERC). FERC’s main concern is assuring the maximum seasonal flow capacity of an interstate gas transmission system. Therefore, compressor stations must have sufficient available driver horsepower to meet compression horsepower requirements for each compressor installation regardless of whether full driver horsepower is needed or used. This criterion must be met for FERC to certify the interstate transmission system’s maximum seasonal capacities.

FERC does not directly address oper-ational flexibility and efficient operation to certify compliance and therefore pipe-line compressors rarely operate near their design point. Operational flexibility and efficient operations are left to individual interstate transmission companies since system throughput varies throughout the year due to daily and seasonal fluctua-tions of supply and demand. 


This article exposes shortcomings to traditional manufacturer centrifugal compressor performance maps. Yet it is also apparent that these performance maps are not utilized effectively for their gas turbine drivers. This analysis indicates that maximum gas turbine horsepower is not sufficient to utilize the complete compressor performance map because compressor manufacturers generally choose to provide maximum flow design conditions at operations around 80% turbine speed. Therefore, larger horsepower turbine drives are being specified and purchased to satisfy FERC certification. The maximum horsepower available of a large turbine drive may never be utilized since the compressor manufacturer intentionally chose the FERC certified capacity to occur at a reduced speed (80%).




A gas turbine’s available horsepower depends on atmospheric pressure and temperature. The required compression horsepower depends on pipeline flow conditions (i.e. gas composition, pressure, temperature, etc.).

Centrifugal compressor performance maps provided by vendors provide plenty of operational information (i.e. speed, head, flow, and efficiency); however, this is not necessarily sufficient to determine if the operation of the gas-turbine/compressor unit can satisfy the operational requirements dictated by ambient and pipeline conditions.

The traditional Head versus Flow performance map identifies the performance envelope to determine compression horsepower. These maps may not provide a clear picture of the possible operation available to the user in terms that are commonly used throughout the industry. For the past seventy years, there has been little improvement in user communication via the compressor map format.


Therefore, new methods for evaluating, designing, and optimizing centrifugal compressor maps used in natural gas transmission systems have been developed. Based on these methods, the most commonly used driver that powers many pipeline compressors lacks the flexibility to effectively and efficiently utilize the complete speed and efficiency ranges provided by the centrifugal compressor manufacturer.

 Compressor manufacturers develop performance maps after receiving information based on specified design conditions from pipeline design engineers. This includes the maximum capacity at inlet and outlet design conditions needed to meet FERC certification.

Compressor manufacturers commonly locate the design point (Figure 1) using the design conditions along the highest efficiency line (82.5%) and at or above 80% speed. Yet pipeline compressors rarely operate near their design point resulting in operations at reduced compressor and driver efficiencies, and gas recycling.





The forty-two intersection points within the boundaries of surge and stone-wall can be considered valid operating points from the compressor vendor’s standpoint. But they are not necessarily valid operating points unless the driver can provide the required compression horsepower.


A centrifugal compressor map provides the pipeline design engineer with information to determine where possible compression operations exist given head and flow coordinates. However, the map does not necessarily indicate if operation is possible since ambient conditions dictate if the gas turbine can provide the compression horsepower needed. It would be more useful to have a snapshot of all theoretical and physically possible operating points based on pipeline supply/demand conditions, daily or seasonal variations in pipeline operations, and changes in ambient conditions. These conditions could be substantially different from design condition. A clearer picture of what the compressor/driver can do under off-design conditions would be helpful.

Using the information in Figure 1, Figure 2 provides physically possible operations at the appropriate intersecting speed and efficiency lines. Fortunately, the operation at design conditions is possible at 80% speed as predicted by the compressor manufacturer.

Years of gas industry operating experience with gas turbine-driven centrifugal compressors has shown that operations should not be considered below the 80% speed due to increased maintenance and operational costs. As general rule-of-thumb, a 20% reduction in driver speed translates to a 50% horsepower reduction and an increasing gas turbine fuel rate.

Inspection of Figure 2 shows only the operations with sufficient driver horsepower while Figure 1 shows possible compressor operations without the driver information. Figure 2 is more useful as it identifies those operations that are physically possible due to sufficient available driver horsepower.






Pipeline design engineers use terms like head, ACFM, efficiency, and speed when dealing with compressor performance maps. These terms do not clearly communicate the operation of a centrifugal compressor installation to other functional company groups. Figure 2 lacks the terminology commonly used between functional groups such as volumetric flow at standard conditions, Qstd (MMscfd), suction pressure, Ps (Psia), and discharge pressure, Pd (Psia). More informative compressor performance maps are presented in Figures 3 & 4 with terms commonly used throughout the natural gas industry.






Changes in ambient temperature can readily be presented in this format. Decreasing the ambient temperature from 120⁰F to 32⁰F provides additional operation at 90% speed and three additional operating points at 100% speed (Figures 3 and 4). These charts provide operating points on the compressor performance map where there is sufficient driver horsepower from 50% to 100% speed but without a horsepower amount.

Figure 5 provides additional information concerning available (BHPavail) and utilized (BHPutil) horsepower versus volumetric flow rate (Qstd). Many operating points utilize less than half of the available driver horsepower which limits efficient driver operations. There is a substantial difference in available and utilized driver horsepower at lower speeds. At 50% RPM, utilized horsepower is 17% of available driver horsepower; 99% of available horsepower is utilized at 90% speed.


In the 32℉ ambient temperature case (Figure 6), the utilized horsepower can be as low as 18% and as high as 97% of available horsepower at 50% and 100% speed, respectively. Figure 6 depicts an increase in speed range from 90% to 100% due to the lower ambient temperature with three out of six points on the 100% speed line having sufficient driver horsepower.





A season needs to be selected for optimizing the manufacture’s compressor map. To comply with FERC certification, the winter season (32℉) was selected. The summer season (120℉) was used to bracket optimization.

Maps were developed to show operation before and after optimizing the manufacturer’s compressor map. Three values were generated: 1) BHPreqd: The required compressor horsepower, 2) BHPutil: The utilized driver horsepower needed to physically satisfy compression needs, 3) BHPavail: Maximum available driver horsepower available at ambient conditions. These three values are plotted against Qmax (MMscfd) (Figures 7 and 8) for a 120⁰F ambient temperature.

The following conditions need to be satisfied at all 42 points for complete map operation to be physically possible: BHPreqd =BHPutil ≤ BHPavail. Figure 7 shows substantial levels of BHPreqd above 90% speed. Therefore, operations above 90% speed are not possible. Figure 8 shows after optimization of the initial manufacturer’s compression map additional operations are available at 90% speed.







Prior to optimization, results show an operational improvement at 32℉ (Figure 9). After optimization, all of the required horsepower, BHPreqd, is equal to the utilized horsepower, BHPutil.







As Figure 10 (32℉) indicates, the entire optimized compressor map can be utilized. Figure 10 supports the fact that sufficient driver horsepower is available to allow operations within the optimized compressor operating envelop. The final optimized compressor map with all possible operating points for Winter (32℉) is shown in Figure 11.




A sensitivity analysis was also performed by varying the design inlet pressure +/-50 Psia (Figures 12 to 15). The results indicated no problems in achieving the design flow rate at the design discharge pressure (Pd) with the available horsepower (BHPavial) at 32℉.






As stated earlier, operations below 80% speed should be limited due to increased maintenance and operational driver costs. Even with compressor map optimization, there remains the problem that most possible physical operations exist below 80% gas turbine driver speed.

An alternate compressor driver capable of providing complete and efficient compressor map coverage would be needed to obtain operations on the complete, optimized compressor map. But years of operating experience with gas turbine-driven centrifugal compressors has shown that operations should not be considered below the 80% speed. Thus,


1. Optimization of existing and new compressor maps provides insight into limitations in operational flexibility of large ISO horsepower gas turbines (7,150-31,050hp) given driver constraints.


2. The replacement of a gas turbine driver with a driver that can perform efficiently and effectively at 50% to 100% compressor speed levels is needed to utilize the entire centrifugal compressor map based on the results provided. The complete compressor performance map will be made available at lower speeds in the event that such a driver becomes available.


3. Analysis indicates larger capital-intensive gas turbines are specified because compressor manufacturers chose to provide maximum flow design conditions at inefficient operations around 80% turbine speed. Therefore, users purchase larger horsepower turbine drives and never utilize their horsepower capabilities.




Reconfiguration of interstate natural gas compressor stations from gas-driven compression only to electrical power generation for gas compression and electrical power sales can benefit optimum full-load operation of the existing gas turbines. The excess electrical power produced could supplement renewable energy derived from wind, solar, geothermal or nuclear sources supplying electrical power in the absence of a conventional power station during events such as the 2021 Texas Electrical Reliability Council of Texas (ERCOT) rolling-blackout since the gas supply is available directly at the compressor station(s).

Additionally, if the variable speed electric motor drive becomes an option, replacement of the currently installed compressor(s) with new hermitically sealed electric motor driven compressors should be considered along with adding new electrical generator(s) coupled to the existing gas turbine(s). The existing gas turbine(s) could now operate at 100% load powering the electrical generator(s) to supply power for either gas compression or to the electrical grid. There would be times during seasonal demand for gas compression (Winter residential heating) or power generation (Summer – electrical power for cooling). And if a viable variable speed electric motor drive option becomes available in the 50% to 100% speed range then the electric motor driver’s power characteristics should be used to develop an optimum compressor/driver map. There will be no need to simulate seasonal horsepower changes due to ambient conditions since seasonal changes do not affect the horsepower rating of an electric drive. 



Articles

Evaluation, Design, and Optimization of Centrifugal Compressor Performance Maps

COMPRESSOR MAPS

Oil & gas companies are under intense pressure to decarbonize and lead the energy transition while meeting production goals. For many assets including pipeline compression stations, gas and LNG plants, and production sites, generating the horsepower required for compression can be a significant contributor to both facility emissions and OPEX.


Selecting the type of machine to perform this duty has historically been a binary decision for operators – with most opting for either an electric motor or mechanical drive solution, such as a gas turbine or reciprocating engine. However, a strong business case can be made for combining one or more mechanical drive components with an electric motor (or motor-generator) into a single hybrid/dual drive train. These configurations can offer advantages over single-drive systems including flexibility, efficiency, lower costs, and a reduced carbon footprint.


Many facilities, particularly pipeline compression stations, already feature both electric motor and gas turbine-driven trains. By using different drivers, operators can avoid being locked into a singular energy supply. Operating two trains means at least partial station operation if or when one needs to be shut down for maintenance. However, having separate trains does not always constitute the most efficient equipment arrangement, as one train might be sitting idle for much of the year.

A hybrid/dual drive may be a better option in certain circumstances by affording operators the same flexibility to use available gas or grid electricity as their energy source but without the complexity of installing two trains. This lowers CAPEX as ancillary infrastructure is greatly reduced such as foundations, piping, wiring, cabling, electrical systems, and Balance of Plant (BoP).

Example: Electric motor-driven (EMD) compression is being viewed as one facet of decarbonization. On grids with a high percentage of wind and solar, an operator can use an EMD to run compressors during off-peak hours when prices are low and grid stability is high. The gas turbine would only be started up when electrical power is not available or prices were high.

As the motor can be designed to dually work as a generator, it also becomes possible to use any extra power from the turbine to produce electricity for site duty. The additional electricity can potentially be sold back to the grid. Grid connectivity, too, requires constant gas turbine speed. This can be achieved with advanced electronics. Similar flexibility is also provided by using variable inlet guide vanes (VIGVs).

Another scenario where a hybrid drive can be beneficial is at sites with gas turbine-driven compression trains that experience large temperature fluctuations due to seasonality. Available power from gas turbines decreases as the ambient temperature increases. As a result, units are often oversized to ensure sufficient power during the hot summer months. However, the same gas turbine may generate much more power during the winter than the compression train requires. This results in low-load operation of the gas turbine, reduced efficiency, and increased emissions.

Opting for a hybrid drive by installing an electric motor on the shaft end of the compressor opposite the gas turbine can solve this problem (assuming a grid connection is available). In such cases, a smaller turbine can be selected to operate fully loaded. The motor or motor-generator supplies any additional horse-power required when the temperature rises above design point. If the turbine produces more horsepower than is required for the compression duty in colder months, the motor-generator can be used to produce additional electricity, which can be used at the site or sold to the grid. By running the gas turbine at an optimal load, NO􀀁 and CO emissions are reduced. Fuel consumption and associated CO₂ emissions are also decreased.


Depending on the application and specific type of equipment used, multiple dual drive configurations are possible. In the case of centrifugal or integrally geared compressors with two shaft ends available, a typical arrangement would involve installing an electric motor or motor-generator on one side of the compressor shaft end and the gas turbine on the other. The need for clutches and gearboxes will be determined by the type of motor used and operation of the compression train.

For centrifugal compressors, a typical train configuration would comprise a gas turbine with a clutch on one side and an electric motor with a speed increasing gearbox and a clutch on the other side. With such a setup, the electric motor could be used as the primary driver (the gas turbine as backup) when electricity is available from the grid. Switching between the motor and the gas turbine is possible via engagement and disengagement of the clutches, with minimal disruption to pipeline operation.

For axial inlet compressors, which only have one end for connecting a driver, the motor will have to be installed between the gas turbine and the compressor. The motor acts as a part of the shaft which transmits power from the gas turbine to the compressor. In gas turbine drive mode, the circuit breaker is open and the motor continues to spin without a load.


A utility-scale LNG liquefaction plant in the Northeast United States is being built. It features a gas/electric drive system. It combines a Siemens Energy SGT-300 gas turbine (8 MW), STC-GV integrally geared compressor, and electric motor-generator to ensure stable and efficient operation of the refrigeration/liquefaction train. The compressor is pinion-driven from the gas turbine side and bull gear-driven from the motor-generator side with no need for clutches or a separate gearbox. A single lube oil system supplies oil for the entire train.

During cold months, the gas turbine drives the N₂ refrigeration compressor and the generator, supplying about 3 MW of additional self-generated power to meet the plant’s electrical demand. This reduces the need to purchase power from the grid. When turbine output decreases during summer, the motor-generator acts as a motor to supply additional power to the compression system. After start-up, the facility is expected to produce a baseload of 170,000 gallons of LNG per day and up to as much as 250,000 gallons without shutting down.

The hybrid drive concept has also garnered attention in the downstream sector. In refineries, the Purified Terephthalic Acid (PTA) process is exothermic (releases heat). It normally includes a steam turbine, one or two hot gas expanders, and a motor/generator to export power. The motor/generator starts the process by driving the train to produce air. Once the process is producing steam and off gas, the motor generator is used to export power to the grid. The train is not stopped.

Operators can’t afford a shutdown due to grid instability or lack of available power. Supplementing an electric motor-generator with a gas turbine (or vice versa) in a dual/ hybrid train provides added assurance. 

THE CASE FOR HYBRID DRIVE COMPRESSION TRAINS

DUAL DRIVE COMPRESSORS 

Yaskawa Electric Corp. is one of the world’s leading manufacturers in the fields of drive technology, industrial automation, and robotics. Founded in 1915 and based in Kitakyushu, Japan, Yaskawa strives to optimize the productivity and efficiency of machines and industrial systems via innovation. Today, Yaskawa has 14,500 employees worldwide and a business volume of EUR 3.7 billion.


In 2014, Yaskawa became the sole owner of The Switch. Yaskawa Environmental Energy / The Switch focuses on electrical drive train products, capabilities, and solutions. Included within its portfolio are electrical machines and high-power converters to original equipment manufacturers and system integrators for selected wind, marine and turbo (high-speed) applications.


Its solid-rotor technology integrates with high-speed machinery, and is designed to improve the efficiency, simplicity, and robustness of turbomachinery. A solid rotor is built of a single piece of steel that is not sensitive to thermal cycling. This offers stable and effective bending stiffness combined with an ability to retain its same balancing class. As a comparison, in case the rotor would be made of a plate stack shrink-fitted to a shaft, its stiffness would rely on the axial compression of such a stack. Therefore, it can change over time or when operating in fluctuating temperatures.

“We are known as a provider of robust high-speed electrical machines using solid-rotor technology,” said Markus Silventoinen, Mechanical Engineering Manager at Yaskawa Environmental Energy / The Switch.

 The company also supplies complete high-speed machines for integrated turbomachinery, such as impellers directly on its machine shaft, as well as standalone machines that connect to adjacent machinery via a flexible coupling. Additionally, it delivers active part components for electric machines that can be integrated with turbomachinery.


The standard solution is to equip the rotor with a copper squirrel cage for improved efficiency and power factor. Efficiencies up to 97% can be reached, depending on the rating of the machine. The cage is made only from solid materials. Further, the company can provide feasibility studies of direct drive electrical machine solutions along with commissioning and service for its equipment.


“Our simplified electrical drive technology and products help optimize the performance of turbomachinery,” said Silventoinen. “The high-speed machine can be coupled directly to the system without other mechanical parts, like gear-boxes, even as a hermetic compressor motor or turbine generator unit. The variable frequency drive (VFD) supports operational optimization via energy savings.”


Some of the key turbomachinery use cases for this technology include:

•	New designs for compressors, turbines,
or pumps
•	Test benches with wide speed ranges
•	Replacing old steam or gas turbine prime movers with standalone machines

Making heat or converting it to electrical energy is a hot topic today, added Silventoinen. New technologies for industrial-size (> 1 MWe) heat pumps are needed to increase efficiency in processes that generate heat for district heating.


“Whether you’re looking for efficient heat pumps or high-speed generators in Organic Rankine Cycle (ORC) applications, solid-rotor technology is a good fit,” he said. “Both solutions typically use radial turbomachinery in >1 MWe powers and need high rotational speeds of 10,000 rpm.”

Solid-rotor technology can also raise the robustness and simplicity of integrated high-speed motors in heat pump applications and high-speed generators in ORC applications.


The organization is currently looking into opportunities for its high-speed technology to be implemented in hydrogen-related applications. And its low-speed permanent magnet machines are being used with generators for offshore wind and with direct-drive shaft generators and propulsion motors for marine applications, both of which can be a part of the future hydrogen economy.


Its latest technology is in-house active magnetic bearings (AMB), which are currently being tested by a pilot customer. Contact-free bearing technology can simplify machines, maximize robustness, and minimize losses for better system efficiency. 

For more information, visit: www.theswitch.com

Solid-Rotor Technology for Turbomachinery Applications

YASKAWA ENVIRONMENTAL ENERGY / THE SWITCH

An ASME Power Test Code 10 (PTC-10) is a closed loop performance test for centrifugal compressors. It is often undertaken in the factory prior to shipping of a new compressor. It is a rather expensive test since it requires complete installation and commissioning of the compressor in the factory.


There are two alternative procedures to test the centrifugal compressor offered in PTC-10:

i. A test with a gas that is very close in composition and thermodynamic properties to the specified (design or guarantee point) gas at pressures and power demand close to the contractual values, called a type 1 test or

ii. A test using a substitute gas that is different from the contractual gas but allows to emulate the aerodynamic operating conditions, usually with an inert gas mixture like nitrogen or carbon dioxide, and at pressures lower than the specified gas, called a type 2 test.

Considering the distinction between the two tests, it appears obvious that by definition the type 1 test is the more desirable choice since it utilizes the actual gas composition rather than an emulated gas. But sometimes the obvious choice is not necessarily the best option or right answer.


Before we dig into the question, let’s provide more details about these tests. PTC-10 tests are tests to confirm aerodynamic compressor performance. Nothing else. There is nothing in PTC-10 about verifying mechanical limits or characteristics. The compressor has a contractually agreed guarantee performance point that is to be verified in a PTC 10 test. i.e., this is a test for compressor power, efficiency, and aerodynamic operating range only.


The operating point is defined by a gas flow, a suction and discharge pressure, a suction temperature, and a gas composition. While a Type 1 test requires the use of a gas composition very similar to the actual design gas composition, a type 2 test allows the use of a different gas, typically an inert gas like nitrogen or CO₂.

In a type 2 test, test conditions are selected so that aerodynamic similarity is reached. The volume reduction due to the compressibility of the gas is retained. Machine Mach numbers are the same as for the contractual operating conditions. This means that all velocity relationships within the compressor are the same as for the contractual conditions. It is not required to operate at the same pressure or flow of the specified conditions, nor will the compressor operate at the same speed or power consumption as required for the compressor at the specified condition. The ASME power test code provides a precise methodology to accomplish this, and the rules for reaching an aerodynamically similar point are well proven, allowing a precise representation of the operating conditions.


The key advantage of using a gas as allowed by a type 2 test is, that the gas, typically a pure or binary gas mixture, is available with a precisely known composition. The thermodynamic behavior, that is the relationships between pressure, temperature and volume, is well known. The use of similarity laws is well established, Mach numbers are retained, and this allows to maintain aerodynamic relationships. The gas mixture used in a type 1 test will generally not provide that advantage. Therefore, a type 2 test will generally provide more accurate performance test results.

Furthermore, the setup time, test duration, and costs for a type 1 test are significantly larger than for a type 2 test. Test stand capabilities, and the available power of the test stand drivers have to be considered when deciding since a type 1 test usually requires more power and thus larger drivers. For a type 1 test, the gas must be carefully mixed from several components, and the mixture concentrations have to be maintained throughout the test to avoid uncertainties.


On the positive side, the operating conditions required for a type 1 test can provide information about the rotordynamic and mechanical behavior of the compressor. However, the test code by itself does not provide any requirement to monitor or measure these characteristics. The ASME PTC10 code is strictly an aerodynamic test code. There are other tests, mentioned in the API 617 standard, such as a full load, or full speed and full pressure tests, that are designed to verify the rotordynamic performance or the mechanical behavior.


In other words, the extra effort to conduct a PTC 10 Type 1 test does not lead to more precision regarding the aerodynamic and performance results than a type 2 test. It may actually result in reduced accuracy since there are higher gas composition measurement uncertainties. And it certainly will significantly increase the cost and time consumption for a PTC-10 test. 

Klaus Brun is the Director of R&D at Elliott Group. He is also the past Chair of the Board of Directors of the ASME International Gas Turbine Institute and the IGTI Oil & Gas applications committee.

Rainer Kurz is the Manage of Gas Compressor Engineering at Solar Turbines Incorporated in San Diego, CA. He is an ASME Fellow since 2003 and the past chair of the IGTI Oil and Gas Applications Committee.

Closed loop compressor performance test comparisons

MYTH: AN ASME PTC-10 TYPE 1 IS BETTER THAN A TYPE 2 TEST

Supercritical carbon dioxide (sCO₂) power cycles are Brayton cycles that utilize sCO₂ working fluid to convert heat to power. They offer the potential for higher system efficiencies than are possible with other energy conversion technologies such as steam Rankine or Organic Rankine cycles; especially when operating at elevated temperatures. sCO₂ power cycles are being considered for a wide range of applications including fuel-fired systems, waste heat recovery, concentrated solar power, nuclear power generation, and energy storage.


The unique properties of sCO₂ offer benefits over steam as a working fluid in closed and semi-closed cycles to absorb thermal energy, to be compressed, and to impart momentum to a turbine. The supercritical state of CO₂ – nominally above 31℃ (88℉) and 7.4 MPa (1070 psia) – is easily achieved.

Above these conditions is a supercritical fluid with compressibility but with higher density compared to steam or air. This results in much smaller turbomachinery (a factor of 10:1) for a given power level.
Given these attributes, sCO₂ power cycles can offer several potential benefits:

Higher cycle efficiencies due to the unique fluid and thermodynamic properties of sCO₂

Reduced emissions resulting from lower fuel usage

Compact turbomachinery resulting in lower cost, reduced plant size and footprint, and more rapid response to load transients

Reduced water usage, including water-free capability in dry-cooling applications in applicable site conditions

Heat source flexibility applicable to zero and low emissions heat sources.

To facilitate the development and commercial deployment of the indirect sCO₂ cycle at elevated turbine inlet temperatures, pilot-scale testing is required to validate both component and system performance under realistic conditions at sufficient scale.


Accordingly, GTI Energy, Southwest Research Institute (SwRI), and General Electric Global Research are executing the Supercritical Transformational Electric Power (STEP) Demo project to design, construct, commission, and operate an integrated and reconfigurable 10 MWe supercritical CO₂, (sCO₂) pilot plant test facility.


The project is funded partially by the US DOE’s National Energy Technology Laboratory (NETL) as well as team members, component suppliers, and Joint Industry Program (JIP) members. The facility is located at SwRI’s San Antonio, Texas, USA campus. Its goal is to facilitate sCO₂ cycle-based power generation commercialization. With the design phase complete, Phase 2 is now well underway in a dedicated 22,000 ft² building.


There are several objectives in mind for this ambitious project. As well as demonstration of the operability of the sCO₂ power cycle, researchers want to verify component performance, and demonstrate the potential for producing a lower cost of electricity, a thermodynamic cycle efficiency of greater than 50%, and a ≥ 700℃ turbine inlet temperature. Additionally, they plan to validate a recompression closed Brayton cycle (RCBC) configuration.


A couple of different configurations will undergo testing. The initial system configuration will be the sCO₂ simple cycle operated at turbine inlet temperature of 500℃ and pressure of 250 bar. It comprises a single compressor, turbine, recuperator, and cooler. This configuration offers the shortest time and lowest risk to obtain steady-state and transient data. It is particularly relevant to waste heat recovery applications from small simple cycle gas turbines. An RCBC configuration, operating at 715℃ and 250 bar, will follow to demonstrate the highest efficiency potentially achievable within the limits of state-of-the-art known and approved materials.

Plenty of work has gone in to ensuring the various components are fit for purpose. Here are a few examples:

The 10 MW turbine has been tested in a predecessor project at 1 MW to 715℃ and 27,000 rpm. Improvements for 10 MWe testing include increased rotor life (100,000 hours), shear ring retention rather than bolts, couplings on both shaft ends, and improved aerodynamic performance with an optimized volute flow area.


Control of the flow to the turbine and shut off in an emergency situation requires a special control valve adapted from a GE Power commercial steam turbine to accommodate sCO₂ fluid and the operating temperatures. When needed for an emergency shutdown, it will close in under two tenths of a second. It uses Haynes 282 high temperature nickel alloy material, advanced stem sealing, and compact self-contained actuators leveraged from commercial designs used by Baker Hughes.


The compressors leverage an existing commercial Baker Hughes product line as well as work undertaken by GE and SwRI in the DOE-funded APOLLO program. The compressor rotors are a monolithic design for the reduced size impellers inherent in this compact sCO₂ power cycle. Like the monolithic turbine, these have been 5-axis EDM machined by Baker Hughes in its shops in Florence, Italy.

Various operating scenarios have been addressed, including low-speed start of the compressor under liquid or two-phase conditions. During a pressurized hold, the sCO₂ loop will cool to ambient temperatures and liquid CO₂ formation is likely. Restart with liquid or two-phase CO₂ is required to avoid loop blowdown and control flexibility is a requirement with special care and monitoring to warm up under low load and avoid potential equipment damage.

Component commissioning of the system is ongoing with plans to complete plant construction in early 2023. The team expects to complete the initial phase of testing later in 2023 with publication of results and findings to follow. 

10 MW DEMONSTRATION PROJECT UNDER CONSTRUCTION

SUPERCRITICAL CO2 

The Turbomachinery Expo took place again in 2022 for the first time since 2019. Rotterdam in the Netherlands hosted the event. About 2000 people attended around 1000 technical presentations as well as 16 panels, 38 tutorials, three special lectures, two plenary sessions, an exhibit hall, and a keynote – a lot to pack into one week.


Vendors such as Southwest Research Institute, Shell, Uniper, ETN Global, Air France KLM Group, Deltalinqs, Siemens Energy, and Rolls Royce covered a wide range of topics. Supercritical CO₂, hydrogen, and decarbonization were in the forefront. But they were balanced out by plenty of briefings on coatings, maintenance, gas turbine and compressor advances, liquefied natural gas (LNG), research on turbomachinery innovation, and more.


The week began with a keynote on the future of propulsion and power. A range of speakers offered their views on the energy transition and how it will impact aviation, power generation, and oil & gas.

Victor van der Chijs, Chairman of Deltalinqs, representing the logistics, port, and industrial companies in the port of Rotterdam, welcomed everyone to the city. He noted that The Netherlands obtains 55% of its energy demand from renewable sources and is actively engaged in building hydrogen infrastructure. Yet he emphasized the need to balance renewables with gas-fired generation.

Christer Björkqvist, Managing Director and founder of ETN Global, followed to present the overall theme of the keynote as the “Energy Trilemma.” This, he said, is all about balancing three things:

•	Access and affordability
•	Security of supply
•	Environmental Sustainability.
He invited several speakers on stage to elaborate on this theme.

Priscilla Chandrasekaran, Global LNG Technology Innovation Manager at Shell Global Solutions International, covered the various synergies between LNG and hydrogen as well as what the decarbonization of LNG means in the real world. It requires the acceleration of the production of hydrogen-ready GTs. Options need to be available to retrofit such machines into existing plants as well as offering models for new facilities.


She noted the growing supply/demand gap. Current production levels need to double over the next two decades in order to keep pace with demand projections.


“We need to make the decarbonization of LNG simple and affordable,” she said. “Retrofits need to be accomplished without months of downtime or the need for complex fuel gas management systems.”

Dr. Thomas Thiemann, Senior Vice President, Siemens Energy, added that although countries such as Germany had achieved rates of around 50% renewable generation on the grid, the fact remains that there are long periods without wind and sun in Europe. He championed batteries and pumped storage as ways to increase the value of renewables by storing energy. Batteries were characterized as providing short-term power for the minutes and the hours when wind or solar are offline. But they are not a viable solution when the energy shortfall lasts for days. That is where LNG and gas-power generation come into their own. But these systems also need to become hydrogen ready.


Pedro Lopez Estebaranz, COO, Uniper and Michael Grootenboer, Senior Vice President Engine Products for the Air France KLM Group, continued the theme of the energy trilemma, wrapping up the opening morning.


As the foremost technical and research-oriented show in the world of turbomachinery, the Turbo Expo always serves up a wide variety of sessions. Here are just a few of the highlights:


Southwest Research Institute (SwRI) delivered a tutorial as an introduction to supercritical CO₂ (sCO₂). There has been much interest on sCO₂ for the past decade. Ten years ago, it was the talk of the show, but progress since that time has been slow. The session provided a good grounding of specific areas related to sCO₂ power cycles, demonstration test facilities, heat exchangers, turbomachinery, materials, and the various fluid properties of CO₂ and CO₂ mixtures.


Presenters mentioned sCO₂’s role in the decarbonization of the power generation sector, transportation, and industrialization processes. But there are practical challenges to overcome. Current research is addressing these challenges to bring the technology to commercial fruition.

A later panel addressed the digitalization journey of the propulsion and power industries. It will require large investments as well as cultural changes to realize the promise of digitalization: improvements in workforce efficiency, increased pace in design, manufacture and test, and greater interconnectivity driven by more compute power, modern IT hardware, and faster digital networks. These gains, in turn, require an understanding of the data needs of the digital age. A vast amount of data already exists in organizations. It needs to be better managed and utilized to support data-driven decisions and to create a data-centric culture. Challenges abound in areas such as data gathering, storing, handling, and interpretation of data.


Another tutorial by a speaker from NASA Glenn Research Center delved into environmental barrier coatings (EBCs) for gas turbine applications. The implementation of ceramic matrix composites (CMCs) in the hot section of gas turbines, for example, can lead to increased thermal and propulsive efficiency as a result of their high temperature capability, high strength-to-weight ratio, and toughness. However, problems need to be overcome.


The SiO₂ scale responsible for oxidation resistance at high temperature for SiC-based CMCs, for example, is subject to rapid volatilization by water vapor generated as a byproduct during the combustion process. Subsequently, enhanced oxidation and rapid surface recession occurs resulting in decreased structural integrity and reduced lifetime. To combat the volatilization and surface recession due to water vapor, EBCs have been developed to protect CMC components. EBCs are considered an enabling technology for SiC-based CMCs as they are critical for durability, and longer life. The tutorial encompassed an understanding of the environmental degradation mechanisms of SiC-based ceramics, a history of EBC development, an introduction to EBC failure modes (such as oxidation, recession, thermomechanical fatigue, degradation by calcium-magnesium-aluminosilicate deposits, solid particle erosion, and foreign object damage), an introducion to environmental durability test methods and characterization of EBCs, and future directions and challenges.


Hydrogen, of course, came in for attention at the show. One of the top hydrogen-related sessions considered what would be needed to develop and deploy hydrogen technologies for the generation electricity and the powering of aviation. Panelists noted the present state-of-the-art for hydrogen generation and transport, energy storage, and how hydrogen can best be deployed for power and propulsion. Additionally, they delved into the challenges in converting current and installing new infrastructure for handling, transporting, and storing hydrogen.


Sarah Hopkin, Hydrogen Researcher at Shell Oil, emphasized that for hydrogen to succeed, pipelines were needed that could contain hydrogen safely, as well as carbon capture, utilization, and storage (CCUS). There are already around 5000 km of hydrogen pipelines in the world, mostly in the US and Europe. While the industry has been piping hydrogen for a long time, there is little experience in repurposing existing pipelines for hydrogen. Part of the problem is that the presence of hydrogen affects the fatigue properties of steel.


On the same pane, Tim Allison, Machinery Department Director, Southwest Research Institute, focused on the machinery needed for evolving energy storage applications. He began by stating that California managed to power its entire grid by renewables for a brief period recently. But during the late afternoon and evening, non-renewable sources must be available to meet any supply shortfall. Further, the existing turbomachinery supply chain is ideally suited to take on the challenges of energy storage. Turbomachinery, he said, decouples power from duration. Machinery-based systems can be utilized in pumped hydro, compressed air energy storage (CAES), liquid air energy storage, and other applications to lower the cost of long-duration energy storage. 

SPEAKERS STRESSED HYDROGEN, DECARBONIZATION, SUPERCRITICAL CO2, AND LNG

2022 TURBO EXPO

During a few very hot and calm weeks in July of 2022, more than 30,000 MW of Texas wind power was operating at less than 8% of rated capacity. At the same time, demand hit record levels. Fortunately, the state scraped by without blackouts. In February of 2021, however, a similar no wind period during an unusual cold spell also knocked out some fossil fuel and nuclear generating capacity. It caused blackouts lasting for days across the state and multiple deaths, mostly due to a lack of heating.


Such occurrences aren’t confined to Texas. It is common for parts of California to run out of power on hot days when there is little wind after the sun goes down, or on hot cloudy, windless days. Northern California, in particular, has suffered rolling blackouts for the last couple of summers. But now Southern California is beginning to experience similar issues.


The popular solution to such problems is battery storage. The basic concept is to place battery farms at strategic points. These batteries would be used to store excess off-peak renewable energy which could then power the grid when wind or solar falter during peak periods. However, batteries are expensive, have a lifetime of less than 12 years, have a large physical footprint, and are practical for only a few hours of energy storage. They are a good short-term emergency power source and will undoubtedly play a role in the future energy mix. But they don’t solve the underlying problem – if the grid is down for more than a few hours, longer duration energy storage is required.

To accomplish a high penetration of renewable energy on the grid (more than 20-25%) while maintaining reliability, long-duration energy storage systems are required that can store multiple days of energy. Hybrid, long-duration energy storage systems can fill this need.


Like a plugin hybrid car, long-duration hybrid energy storage systems store electricity at off-peak times and return it when needed with the addition of some fuel. And like the plugin hybrid, these systems offer synergy.

Energy density: the same factor that gives the plugin hybrid much greater range than a full electric vehicle (EV).


Some plugin hybrids allow the engine and batteries to be used together to provide short bursts of power greater than what the battery or engine alone can supply, just as hybrid energy storage systems can return energy to the grid at a rate faster than the maximum charge rate, something batteries can’t do.

As with the plugin-hybrid vehicle, there are CO₂ emissions, but this is largely offset by charging at off-peak times with renewable energy, and the reduced environmental impact from the mining and manufacturing of the equipment compared to the manufacture of lithium ion batteries.


When the battery goes dead on the plugin hybrid the car can still run on the engine. When the stored energy in the hybrid long-duration energy storage system is used up, they can still produce about 30% of their power by burning fuel. 

Plugin hybrids cost more than an engine driven car but less than a full electric vehicle –the long duration hybrid energy systems cost more than a peaking gas turbine but less than the same kilowatt-hour battery storage system


Compressed air energy storage (CAES) is a proven method of long duration hybrid energy storage. There are currently two of these systems in operation that have been running for several decades: the 330 MW plant in Huntorf, Germany; and the 110 MW system in Macintosh, Alabama. These installations use off-peak power to compress air that is stored in underground salt caverns. They return more than 120% of the stored power to the grid at peak times by heating the air in a natural gas-fired combustor and expanding the hot, high-pressure air through a turbine driving a generator. The fuel rate is 30% better than that of a modern combined cycle power plant. The main drawback of CAES technology is the requirement for a location with very specific geology.

But CAES isn’t the only game in town for long-duration storage. Several novel approaches to hybrid energy storage technologies are under development. These systems will allow a higher penetration of renewable power while maintaining grid reliability. Each of these systems is turbomachinery intensive.


Pintail Power’s Liquid Salt Combined Cycle system is probably the easiest of these technologies to implement and is currently being marketed. The system uses gas turbine exhaust to pre-heat feed-water and superheat steam. But the hard work of converting the pre-heated water to steam is handled by a steam generator using liquid salt heated by electrical resistance heaters using excess off-peak renewable energy.


This is the same liquid salt that has been used successfully in concentrated solar power (CSP) systems as well as a heat transfer fluid in refinery applications. The salt has a lifetime beyond 20 years. While salt is capable of being heated to well over 1000℉, Pintail’s system limits the temperature to about 800℉ to avoid the need for special alloy steel piping and heat exchangers. When added to an existing combined cycle power plant, it doubles the output and improves the heat rate to less than 5000 BTU/KW-HR (68+% efficiency). Liquid salt combined cycle technology is scalable from under 50 MW to over 600 MW.


Just In Time Energy has devised two approaches to long-duration energy storage, both based on the same technology. Its Optimized Liquid Air Energy Storage System (LAES) is an improvement over traditional LAES technology. LAES systems use off-peak power to make liquid air. At peak times, liquid air is pumped to high pressure, vaporized, heated, and expanded in a turbine to make power. While the basic concept has been around for more than 30 years, there is only a single pilot plant in operation.


Several air separation companies have proposed LAES systems, but all these systems use a regenerator vessel to store the phase change cold from the pumped liquid air as it is vaporized prior to heating in some type of heat absorbing media. This cold is used to reduce the power consumption when making the next batch of liquid air. The problems with this concept are: the regeneration vessel is almost as large as the liquid air storage tanks; it is operating at the pump discharge pressure; and fabricated from expensive cryogenic materials.

The heat rate of these systems ranges from about 3500 BTU/KW-HR to 5000 BTU-KW-HR and they have an energy ratio (on-peak produced electrical energy/off-peak energy consumed) between about .75 and 1.2, depending on the configuration. Energy density ranges from about 320 to 370 KW-HR per cubic meter of stored liquid air.


Just In Time Energy’s 105 MW Combined Gas and Electric Storage System uses the same concept as its Optimized LAES system except that the working fluid is liquefied natural gas (LNG) from a pipeline, produced at off-peak times with excess renewable power. These systems store excess renewable energy at off-peak times as LNG. They return electric energy to the grid and gas to the pipeline system at peak times.


As the second expansion in this cycle is down to the pipeline system pressure rather than atmospheric, heat rate is typically less than that of Optimized LAES, but still under 5000 BTU/KW-HR. The energy ratio varies between about .75 and 1.0, Energy density is about 130 KW-HR per cubic meter of storage. This system has two primary revenue streams – the value of the power returned to the grid and the value of moving the natural gas from off-peak to peak times.


Potential applications include new or existing peak-shaving LNG plants as well as LNG import and export terminals. On the export side, this technology could facilitate arbitrage between spot market LNG sales and spot market power sales. Additionally, this could work well in areas such as NY state where there is both a need for on-peak power and gas, and where excess off-peak power and pipeline gas is available.


Another possible application is in natural gas storage sites that use depleted oil or gas production fields (about 80% of the gas storage sites in the U.S.). At most of these storage fields, the discharge pressure decreases sharply as discharge flow increases at peak times. This limits the flow from the field and requires compression power to get the gas into the pipeline system. By taking gas from the field at off peak times and producing LNG with excess renewable energy with the Combined Gas and Electric Storage System, gas can be returned to the pipeline at peak times in combination with the normal flow from the storage field. Concurrently, peak time power can be sold to the grid.


When not producing power, all three of these new energy storage technologies can be used to improve grid stability by adding VARs (Volt-Amps-Reactive) and inertia to the grid. This is achieved by including overrunning clutches between the generators and turbine drivers. These clutches allow the generators to stay synchronized with the grid after the turbine drivers are shut down. Further, clutches placed between turbines and generators allow faster starting and potential spinning reserve credits in certain markets.


This is particularly important in light of the increased presence of renewables and a general trend to decommission coal plants and aging gas turbines plants. Wind and solar power provide very little VARs to the grid and almost no inertia. Low VARs reduces the power factor on the grid. This results in overheating of transmission lines and reduction in the overall power handling capability of the grid. A lack of inertia, on the other hand, limits short-circuit current capability and makes it difficult to maintain a constant frequency. 

RENEWABLES REQUIRE SHORT- AND LONG-DURATION STORAGE 


LONG-DURATION STORAGE

Let’s begin with a home-appliance analogy. Modern refrigerators come with a long list of features including sophisticated temperature settings, voice control, alerts when certain supplies are low or the milk goes bad, and more. On the downside, their motherboards sometimes struggle to cope with cold temperatures. Hence, you sometimes hear people longing for the old days when an old-school freezer could last for decades. However, those old freezers were also energy hogs and would be unlikely to receive an acceptable Energy Star rating. In any case, their manufacturing costs would probably be difficult to justify today.


Similarly, I’ve been to trade shows and heard veterans lament the demise of old turbomachinery control systems. They complain that the new versions come with all kinds of digital bells and whistles, yet they sometimes lack reliability and can be difficult (or expensive) to fix. There can be some truth to their assertions. Yet, modern controls can do so much more than legacy systems.


Gone are the black box controls, replaced by open standards. Integration with other systems is far easier. Plant-wide, fleet-wide, and grid-wide controls become feasible as everything is running on the same set of protocols and standards. A maintenance person no longer must walk a mile to take a reading from a dial. That same function can be carried out at remotely via centralized controls.


Meanwhile, the turbomachinery controls vendor community continues to innovate. Companies such as Elliott Group, EthosEnergy, Continental Controls Corp., Siemens Energy, Honeywell, Solar Turbines, Mitsubishi Power, Emerson, and Rockwell Automation are steadily introducing more technologies and features into their tools. Let’s hear what they have to say about the latest trends and products.


Philipp Lange, Solution Manager for Controls Modernization at Siemens Energy has noticed several trends impacting the controls space. This includes a greater focus on functional safety in all areas of turbomachinery control, as well as digitalization, which brings about virtualized applications, data-driven maintenance approaches, and paperless documentation. He also noted the slow emergence of “low-manned” operation of certain assets.

“The pandemic highlighted the usefulness of remote capabilities, but also showed there is room for improvement to realize their full potential,” said Lange.


Accordingly, Siemens Energy has added a variety of remote monitoring, digitalization, cybersecurity, safety, and compliance enhancements to its controls. In addition, the company is looking into technologies such as 5G networks and rugged smart mobile devices that could help address the skills shortage due to workforce retirements and limited accessibility.

The Siemens Energy SPPA-T3000, for example, has been upgraded to address cybersecurity challenges such as online patching, user management, improved hardening, and digital signatures. This has enabled these controls to earn IEC and ISO certifications for security. Further advances include the use of object-oriented project databases, augmented reality for guided commissioning and operation, as well as cloud-based infrastructures to provide engineering and testing environments independently from location and available hardware.


SPPA-T3000 will also be enhanced with SCADA functionalities to control multiple distributed remote assets. New simulation capabilities built into SPPA-T3000 aid users in working on digital twins of their own assets to create test scenarios for any adaptions without impacting the real system.

Continental Controls Corp. offers a range of fuel control products for gas turbines and gas engines. For example, its pressure control valve handles a variety of gases that are typically delivered at a low pressure with a lower capacity than primary fuel control valves. This valve is also used to control what would have been flare gas by admitting the gas into an enclosed combustor.


Rick Fisher, Vice President at Continental Controls, noted several trends including: the desire to blend various gases to reduce greenhouse gas emissions (GHGs); instead of recording fuel consumption for two or more units, a requirement is evolving to include unit specific flow consumption; and due to regulations about venting of excess gas, users are exploring the options to eliminate gas flaring and minimize fugitive emissions.


“Controls vendors will need to know how to mix and change the mixture as needed to maintain efficient operation and emissions reduction,” said Fisher. “Valve manufacturers will need to have secondary control valves to control the proportion of gases in the mix as well as gas mixers to provide a homogeneous mix.”


Continental Controls provides variable pressure control valves and venturi mixers to allow for precise blending of fuels. It is currently engaged in qualifying all its gas turbine products for up to 25% hydrogen.

EthosEnergy EcoMax is a Dry Low Emissions (DLE) and Dry Low NOx (DLN) automated tuning technology that continuously optimizes output, emissions and combustion dynamics. This eliminates the need for manual gas tuning approaches that can lead to untapped capacity and efficiency.

Take the case of a 775 MW combined cycle power plant in Turkey where two GE Frame 9FA gas turbines suffered from combustion chamber issues that caused the engine to trip. The facility implemented EcoMax to eliminate the trips during changes in temperature. As well as major financial savings, the plant has gained improvements in reliability, output, better manage its emissions, and reduced the risk of human error through manual tuning, according to Hande Puhaloglu, Sales Account Manager, EthosEnergy.


She, too, noted a definite trend toward hydrogen blends. The company has signed a partnership agreement with Politecnico di Torino for the research and development of technology to allow for the conversion of 40 MW gas turbines to accept up to 40% hydrogen.


“Plant operators are asking for control systems that can collect more qualified data and smarter solutions so that they can be more efficient and flexible while operating the plant".

For turbomachinery control, Rockwell Automation focuses primarily on controls for single-stage compressors and one- and two-valve steam turbines. They include communication and diagnostic capabilities for improved uptime. It has recently been expanding its condition monitoring product portfolio for compressor control systems. The Dynamix 1444 Integrated Condition Monitoring System, for example, operates in conjunction with its Emonitor condition monitoring software and condition monitoring sensors.

“Emonitor condition monitoring software provides automated analytics capabilities for users,” said Andries Ernst Kruger, Engineering Team Lead for LifecycleIQ Services at Rockwell Automation.

Tom Logan, Senior Manager, Technology Integration – Intelligent Solutions, Mitsubishi Power Americas, highlighted trends such as operational flexibility, reliability, cybersecurity, and support for hydrogen and ammonia.


“Extreme weather events, like what Texas experienced in February 2021, the grid complications related to intermittent renewable sources, and the grid frequency impacts related to solar are driving the demand for flexibility and reliability solutions,” he said.


As a result, users want turnkey solutions that incorporate plant hardware and controls logic, and that provide improved capabilities. For example, Mitsubishi Power has invested heavily into its Tomoni portfolio to provide users with faster startup, higher ramp rates, continued operation during extreme environmental conditions, analytics, and a route to decarbonization.

A recent controls scheme project validated fuel blending of hydrogen and natural gas at partial and full load on an M501G natural gas turbine. This was done at Georgia Power’s Plant McDonough-Atkinson in conjunction with Electric Power Research Institute (EPRI) with a 20% blend. New instrumentation and control logic protected the turbine during fuel transitions and sudden fuel mix changes to support safe operation. The electrical ratings of all components in hazardous areas had to comply with NFPA Class 1, Div 2, group B criteria.


“Reviews of grounding were critical since the minimum ignition energy of a hydrogen-air mixture is one-fifth that of natural gas,” said Logan.


Gas turbine instrumentation was modified to increase the speed of measurement response time utilized to detect abnormal combustion. The application of higher speed devices also required review of prior control setting limits to verify that the higher speed of the new devices would not impact the protective logic associated with prior devices. In addition, over-firing logic had to be applied for the case where the gas turbine is operating on blended natural gas and hydrogen fuel under the condition that the hydrogen fuel supply tripped and natural gas operation continued. The sudden stopping of hydrogen would result in an increase in natural gas flow that would exceed the heat input required for base load operation and would result in over-firing of the gas turbine. New logic helped the system react quickly to the loss of hydrogen and inject a feed forward response to the position of the throttle valves.

On the cybersecurity front, Mitsubishi Power’s Netmation Protect Pack provides an NERC CIP compliant operational technology (OT) network with a smaller attack footprint. The physical security of this server-based system is easier to maintain than that of individual human-machine interface (HMI) stations. It provides centrally managed access control, an integrated intrusion detection system, and antivirus and malware protection, as well as failover capabilities, centralized disaster recovery, and automated backup and patching

Klaus Brun, Director, Research & Development, Elliott Group, pointed to digital twins as a growing trend along with self-learning neural networks being used to augment turbomachinery controls. This raises the capability of analyzing large amounts of sensor data being collected on modern turbomachinery. Also, advanced diagnostic and rotordynamic monitoring capabilities are emerging within compressor control systems. In addition, Brun is seeing greater usage of remote and fleet monitoring systems for improved, continuous monitoring and analysis of equipment operations on an OEM’s fleet. In some cases, operators are integrating these systems with plant SCADA systems for improved operational control and efficiency.


“Improved diagnostic capabilities can help to identify potential machinery problems early to schedule required maintenance and to avoid shutdowns due to failures,” said Brun. “Digital twins have demonstrated the capability to identify and reduce performance losses due to fouling and equipment degradation.”

Elliott Group works with Tri-Sen as its primary controls solution provider to develop machinery control systems that are customized for customer requirements and Elliott designs. They are equipped with mechanical and aerodynamic diagnostic features such as a digital performance twin, rotordynamic analysis, remote monitoring, non-linear surge control, and optimized integrated plant load-sharing. The newest Elliott Tri-Sen Gemini control system also includes machinery health monitoring and predictive forecasting to detect operational problems early on. The digital twin that Elliott provides is based on the selection tools for the original compressor design and is automatically remotely updated to reflect the most up-to-date performance prediction for individual compressors. The Gemini control system also includes mechanical diagnostics capabilities such as rotordynamic waterfall, orbit, FFT and bode plots to help identify and address any potential mechanical issue early and quickly. It can be accessed and monitored remotely using any mobile platform. Cybersecurity safeguards are built in.

Bret Walter, Engineering Consultant for Rotating Equipment and Turbomachinery Controls, Honeywell Process Solutions, has observed a trend of users moving away from the proprietary black box solutions for turbine and compressors controls. Instead, they favor a distributed control systems (DCS) that can handle the fast process response times required for turbine governor, and compressor anti-surge and performance controls.

Traditional black box vendors, therefore, will have to adapt to meet customer requirements to run turbine governor and compressor anti-surge & performance controls inside the DCS. Honeywell is responding to these trends with Experion controller and IO Hive technology. It delivers a range of features to facilitate modular and parallel project execution and is based on a resilient, high-speed Ethernet field IO network that connects controllers to Honeywell’s Universal IO mounted in the production areas. Additionally, the company offers asset management via Honeywell Forge Asset Performance Management (APM) Asset Sentinel. It offers early detection of issues with the turbine and compressor while enhancing machinery monitoring and protection systems. Further, the Honeywell Experion PKS Turbomachinery Control Solution integrates with Honeywell’s Safety Manager Safety Controller SC300 to provide an API-670 / IEC-61508-compliant system for safety interlocks of the turbine and compressor. 

Remote Monitoring, Digitalization, Cybersecurity, Artificial Intelligence, Hydrogen Blending, Auto-Tuning, Big Data, and Digital Twins.

September/October 2022