Operators of larger rotating machinery are often confronted with varnish deposits on journal bearings. Varnish is an oil-derived deposit based on machine operating conditions, the formulation of the oil, and contamination. It is responsible for continuous temperature increases on journal bearings as it acts as an insulator, preventing the lubricants from performing one of their most important tasks: cooling. This can lead to unplanned machinery downtime and bearing damage.

In the past, it was common practice to replace the oil. The new oil dissolved most of the remaining varnish from internal parts. However, lube oils used nowadays have low solubility. Oil replacement only helps for a short period before problems return. 

OEMs and lubricant vendors tend to recommend a flushing oil to clean out the system. But the use of a flushing oil with high solubility and high temperature makes it necessary to continue flushing for at three or more weeks to dissolve all varnish deposits. 

If varnish is detected at an early stage, it is possible to increase the solubility of the lube oil using additives for several months before a planned oil replacement. An ESP (electrophysical separation process) filtration unit can also be used to remove the existing varnish. On heavy contaminated systems, though, this becomes inefficient as the ESP filters cannot handle high amounts of varnish since they saturate quickly.

The most effective solution is a chemical cleaning between oil changes. Most service suppliers specialized on chemical cleaning use the same approach as they do when cleaning a heat exchanger, a vessel, or a tank. This can lead to problems such as the wrong chemistry or leftover residue of chemistry in a lube oil system, which can have catastrophic consequences for the system and adjacent machinery. Poor cleaning results has given the practice a poor reputation.

Here is a high-level summary of best practices for chemical cleaning: 

Effective chemical cleaning of a lube oil or hydraulic oil system begins at the planning phase. It is important to prepare a complete mapping of the system and walk visually through it to verify that piping and instrumentation diagrams are correct. Also check flange sizes as there are often flanged connections that do not follow normal industrial standards. 

Flushing loops in the system should be planned based on Reynolds Number calculations, and on minimizing the number of bypasses and blinds needed. That makes it possible to calculate the correct pump size to guarantee turbulent flow and chemical flowrate. Choice of chemical depends on temperatures that can be achieved, time constraints, environmental constraints, construction materials of system, and other factors. 

During the execution phase, the oil system is drained before installing the flushing equipment. Close out or dismantle equipment that cannot be exposed to chemicals. Remove oil filters from casings. 

Manually cleaning of oil tank internals can be performed if the tank is big enough. Otherwise, chemical cleaning is performed.

When the system is ready, the compressor deck has to be cleared for half an hour to do a pressure test of the system. This is the time to fix potential leakages when only water is in the system. For a typical two- to three-week overhaul, flushing is done during night shifts when no one is working on the compressor deck. 

Flushing with water removes chemical residues. Thus, it is important to use chemicals that are soluble in water. Water flushing takes one day on average. Afterwards water is drained, and flushing skids are disconnected. 

The auxiliary oil pump can now be put into operation and the system filled with the minimum amount of oil needed to test run the system. A short oil flushing removes any remaining water then drain the system again and do a manual cleanout of the bottom of the oil tank. 

It is now time to introduce new oil through a 10-micron filter to remove particulate. Chemical cleaning can leave behind solid particles that were suspended in varnish. Therefore, it is recommended to install a high-volume circulation filter on the oil tank to remove them. 

Prior to start up, install new oil filter cartridges. If the system usually runs with 10-micron filters use five-micron filters for commissioning to ensure all particles are removed. Begin the oil circulation pump system and continue until particle levels are continuously on a low level. 

Chemical cleaning of oil systems is the most effective way to remove all varnish deposits and prevent contamination of new oil. The complexity of this process, however, requires high-level knowledge on chemistry, fluid dynamics, and filtration. 

Articles

Cleaning of lube oil and hydraulic systems increases uptime. 

Chemical cleaning

Power recovery trains (PRTs) are common to industrial processes, such as fluidized-bed catalytic cracking units (FCCUs) in refineries and nitric acid sections of ammonia fertilizer plants. Their purpose is to recover energy from a process regenerator’s flue gases and convert it into mechanical energy to produce power; subsequently reducing the consumption of traditional energy sources.

A typical PRT includes a flue-gas expander, a main air blower, and a synchronous or inductive motor/generator. Some also include a steam turbine (ST) or an auxiliary motor-driven air blower for starting the unit. A PRT integrated control system provides automatic control during various operating conditions.

PRTs are commonly employed in FCCUs, in which:

Catalytic pellets circulate between a cracking reactor and a regenerator, where the carbon deposits that form during cracking are burned off. 

Compressed air from the blower passes to the reactor and regenerator, where it oxidizes the carbon deposits on the catalyst pellets and maintains the fluidization of the bed. 

Hot flue gases from the regenerator pass to the expander, which converts the energy into mechanical power to drive the train. 

If the expander delivers more rotating energy than is needed to drive the air blower, the excess is converted to electrical energy and delivered to the local electrical bus or public utility grid. If not, the generator will motor (draw power from the grid). 

The optional ST is used to drive the air blower when insufficient flue gas is available, and possibly to convert excess process steam to rotating energy that the generator will then convert to electricity and deliver to the grid

An integrated control system has been developed to drive, protect, and sequence the entire PRT. Speed, performance, expander, and anti-surge control applications run continuously to coordinate the control of the expander inlet and bypass valves to maintain the proper flow and pressure for a catalyst regeneration process. Excess energy developed by the system is applied to an electrical grid through the hot gas expander and the generator.

PRT control system should regulate the air flow and pressure in the regenerator by manipulating the air blower inlet guide vanes (IGVs) and expander inlet and bypass valves. It should also manipulate the blow-off valve to protect the air blower from surge and control the rotational speed when the generator is disconnected from the utility grid by manipulating the turbine governor and expander inlet valves. Additionally, it should adjust the expander or turbine power output if the generator breaker unexpectedly trips to reduce the power and prevent the unit from over-speeding. However, it must also maintain an adequate air flow to the reactor and regenerator to prevent the catalyst bed from collapsing.

Here is how it works: The regenerator pressure is controlled by an interacting pair of PRT expander control applications that manipulate the expander inlet and bypass valves. The power recovered by the expander is regulated by the main control loop (primary or alternate), which manipulates the expander inlet valve to keep the expander flow equal to the process fluid production rate. The expander inlet and bypass control applications use the same process setpoint (SP) for both loops. Typically, if the inlet valve control application uses a local SP, it passes that SP to the bypass valve control application. The bypass valve is kept closed as much as possible to maximize energy recovery. Flow is shifted from the inlet to the bypass valve in certain circumstances including when a limit loop is beyond its acceptable range.

The purpose of power recovery train is to recover energy from a process regenerator’s flue gases and convert it into mechanical energy to produce power.

Control system stability is essential in maintaining a constant delta-pressure between the reactor and regenerator, as well as a proper flow of air through the catalyst. This prevents hydrocarbon vapors or liquids from entering the regenerator and causing an explosion and, at the same time, avoiding the ingress of air into the reactor which might lead to a major equipment damage.

PRT start-ups using an ST are performed using the speed control application automatic start-up and warm-up sequences avoiding critical speed ranges. This ramps the turbine up to the synchronous speed with the breaker open and no load.

When the breaker is closed to connect the generator to the electrical grid, the steam flow control application typically steps the governor valve open by a configurable amount to immediately put some load on the generator. Control of the turbine governor valve then switches from the speed to the steam flow control application, which maintains the flow of steam to the turbine blades. The air blower is also loaded to begin supplying compressed air to the reactor and regenerator. The performance control application controls the mass air flow to the air blower by modulating the IGVs. The anti-surge control application modulates the blow-off valve as necessary to protect the air blower from surge.

Once the air blower is supplying compressed air to the reactor and regenerator and the process is stabilized, the expander can be loaded. This initiates the flow of hot flue gases through the inlet valve and transitions the control of the main process variable from the bypass valve to the inlet valve. As the expander is loaded, the steam flow to the turbine is reduced, and the PRT will shift from motoring to generating mode.

If the electrical breaker trips during normal operation, the PRT control system will react quickly to either shed the excess power (to reduce the load on the train) if the PRT was generating power, or begin producing enough power to continue driving the train if the generator was motoring. The system will also begin controlling the speed of the train, which is no longer fixed by the grid frequency.

PRTs require precise and reliable control over a broad range of operating conditions to maximize FCCU availability. FCCUs are operated continuously for long periods, with the main goal of maximizing feed cracking. Occasionally, refineries are forced to operate production units at reduced rates because of machinery or process issues, downstream bottlenecks, upstream process unit trips, seasonal factors, market economics, and feed availability.

This integrated control system can run a PRT in an FCCU, safely overcoming breaker trip incidents by utilizing the load-shedding algorithm. The control system also maintains a proper flow and pressure for a catalyst regeneration process under different conditions. Other features like loop decoupling can help to eliminate cyclic interactions between controller applications. The technology described is equally applicable to PRTs found in other processes.

Author: Nabil Abu-Khader, Ph.D. Training Manager and Global Training Specialist at Compressor Controls Corporation (CCC), Abu-Dhabi, UAE.
For more detailed information about 

the CCC control system developed for
the PRT, nabu-khader@cccglobal.com 

Operation of an integrated control system. 

Power recovery train controls

As market forces push towards de-carbonization and lower cost of operation, efficiency and reliability of gas turbines have become key differentiators among competitors. For Brayton Cycle machines, those efficiency gains mostly come via higher combustion temperatures, lower volumes of cooling flows, and larger blades. As those parameters are pushed to new limits, this also puts pressure on component reliability. 

Intimate knowledge of component temperatures and strains is key to designing around this complex series of trade-offs. But as these components are made of materials that can survive ultra-harsh environments within high performance gas turbines, sensors must be able to mechanically survive the temperatures and g-loads inside turbines while also performing electrically or chemically.

Platinum thermocouples (Type S) are the only way to get accurate real-time measurements on the most extreme stationary hot gas path temperature readings. Technically, they can function up to about 1,800°C. But effective lifetimes above 1,650°C are limited as foreign material diffusion, annealing, and other material failures lead to cracking and intra-grain conductivity failures in a short amount of time. In gas turbine operational conditions, a lifetime of less than 20 hours is typical. Adding 5% and 20% or 0% and 13% rhodium to the platinum leads to create a Type R thermocouple can increase functionality to 1,730°C for hundreds of hours. However, rhodium costs >$2,000 per ounce in recent years. By comparison, platinum is less than $1,000/oz. Type R also has a much lower sensitivity than most other thermocouple types, at only 10µV/°C.

Most thermocouple manufacturers recommend that the long-term operating temperatures of Type S and Type R thermocouples only intermittently approach 1,600°C, with continuous use limited to below 1,400°C. Regardless, thermocouples are the most widely used instrumentation within the hottest parts of gas turbines. They are often also installed on rotating parts.

The thermocouple wires are routed along the rotor to get to a cooler, exposed section of the rotor where active electronics on the rotor take in the thermocouple signals, converting them into short-range wireless signals. These electronics can only work up to 230°C, so are typically installed on the rotor between the turbine compressor and the generator. Thermocouple wires are thus routed from the hot turbine section through the entire compressor. Each disk must be machined to allow the passage of the wires as they route along the rotor along a large proportion of the rotor. While this can be done on a fielded engine, the intrusive nature of the installation and the impacts on disk and rotor lifetime usually limit the use of rotating thermocouples to lab or test bed use.

For temperatures on the much cooler compressor, thermocouples are a useful, long-duration option. Wiring down the rotor and through multiple blade disks is still a tedious and expensive engineering task, but much more tractable the closer the instrumented blades are to the compressor inlet. Compressor blades are more sensitive than turbine blades to mass loading, so the thermocouple installation must be as low-mass as possible to prevent unwanted or unrepresentative vibration modes. On smaller and warmer compressor blades near the outlet, the size of the bonded thermocouple and its wiring are of aerodynamic concern. In these cases, thin film resistive devices are sometimes used. These wired sensors have low profiles and are becoming available at higher temperatures.

Temperature Indicating Paints (thermal paints) are used in hot gas path surface temperature measurements. They provide large surface temperature indications rather than point measurements. They change the chemical and thus optical properties of coatings. These changes are a function of temperature and time. Changes are exponential, with temperature and usually quite fast in time.

For a typical lead-, cobalt- or chromium-based thermal paint, activation times at temperatures of interest (e.g., 1,200°C) are usually five to seven minutes. Longer exposures muddy the reading because the color changes of a paint at 1,200°C for 7 minutes are the same as they are for 1,150°C for an hour. Thus, the paints cannot be left in the engine for a run longer than 60 minutes or readings lose accuracy. Further, these paints are applied in thin coats and are not sintered onto the blades. Therefore, adhesion can be poor after more than a few minutes. If paint flakes off, information is lost. Thus, an engine campaign of only a few minutes must be performed with painted hot gas path parts, then the engine must be shut down and partially disassembled. Parts must be removed so painted parts can be analyzed and temperature maps created. Analysis takes from one to 10 months.

The maximum temperature of commercially available thermal paints is usually below 1,530°C. Accuracy is a concern for temperature indicating paints. Some studies show accuracy is on the order of +/- 0.5% of reading, while others show errors on the order of +/- 5%. Some vendors have patented formulations that change color above these temperatures, but they generally keep these paints in-house. Heavy metals such as lead and chromium used in many paints present a health hazard. The fragility, cost of running dedicated, short engine tests requiring tear-down, health concerns, questionable accuracy, and long lead times for measured data are among the disadvantages of these paints.

Thermal crystals are sub-millimeter grains of silicon carbide that have been neutron-activated to have certain distributions of different sizes of crystallographic dislocations within each grain. These grains are embedded in the surfaces of turbine components, and the engine is run for 100 to 200 hours. Components are then removed from the engine, and thermal crystals are de-embedded from the components, carefully labelled, and sent back to a laboratory for analysis.

In this analysis, x-ray diffraction is used to read the size distribution of the remaining crystal dislocations. As a particular grain sees higher temperatures, different sizes of dislocations within it become healed, meaning the dislocations are annealed or re-crystalized back into near-perfect atomic order locally. By analyzing the before and after size distribution, an inference of maximum temperature is established. While this seems to be a complex method of measuring maximum exposed temperature, vendors claim accuracy at temperatures around 1,400°C +/- 3°C

Thermal crystals have cost and testing inconvenience disadvantages. The longer the test, the more ambiguous and inaccurate results become as dislocation relaxation is a function of temperature and time. A long engine test at 1,100°C may give the same result as a short engine test at 1,200°C. Embedding and carefully removing crystals is laborious. It can take months to obtain the results.

Alternatively, infrared cameras can be used for hot gas path measurement. This technique offers 2D temperature measurements of turbine surfaces in real time, unlike thermal paint or thermal crystals. The components glow with blackbody radiation based on surface temperatures. The camera looks at a range of infrared colors, and attempts to rebuild the Wein displacement graph of that item. If this can be done, the uncorrected temperature of the item can be known. But a correction must be applied based on wavelength, temperature, and the material’s emissivity.

Unfortunately, the emissivity of the materials within a gas turbine varies greatly, and there is a lot of reflection of infrared light. Coatings, too, inhibit accuracy. Finally, infrared camera lenses have sensitivity to contamination, vibration, temperature, and thermal expansion. These reasons combine to make the use of infrared cameras in turbine hot gas paths somewhat rare.

Further methods for measuring air temperatures in hot gas paths are Filtered Raleigh measurements and Tunable Diode Laser Absorption Spectroscopy (TDLAS). They provide optical measurements of different molecular absorptions and reflections of the hot gas itself. While they show promise, they are expensive at this time.

Passive wireless RF technology based on high temperature electrical resonators is a new approach. These sensors can be braze-bonded or Rockide-bonded to turbine blades. Typical sensor sizes are 10mm x 8mm x 0.3mm, resulting in a mass below 0.3 grams and a bonded profile height of less than 0.4mm (16 mils), which help maintain expected blade mass loading and laminar flow across the blade surface. The sensors require no attached antenna, as they are their own antenna. They are bonded in a way that has high heat transfer with the blade. A fixed antenna inside or outside the hot gas path pings the sensor, which resonates at a frequency representing its temperature. They work above 800°C in the field on blades and up to 1,700°C in laboratory settings. The antenna is available in forms that intrude into the hot gas path, if desired. The antenna and flexible cable can withstand temperatures up to 800°C. Non-flexible versions work up to 1300°C. Each antenna can read up to 5 sensors simultaneously. No external cooling is required on the antenna or cable probes, which are 2-7mm in diameter. The wireless range is 4-5cm in fielded systems, though 15-30cm range versions are possible at lower temperature applications.

The system can provide real-time blade metal temperatures across a range of 0-800°C. These sensors can also be used in air temperatures much higher than 800°C, and on early turbine blade rows. They can be read through an overcoat of flame-sprayed thermal barrier coating. Wireless range limits blade metal temperature readings to blade tips with a non-intrusive antenna or the use of an intrusive hot gas path antenna if the sensor is more than 5cm from the hot gas path inner casing. Up to five sensors on five different blades at the same radii can be read by the same antenna.

Strain gages provide blade design feedback. These small resistive devices change their electrical parameters linearly as a function of how much they have been stretched in a certain direction. As they are fundamentally electrical, response times can be fast, allowing for blade vibration monitoring. For larger blades, vibration modes need to be characterized across frequencies from 50 to 1000 Hz in most cases. For smaller blades, dynamic strain frequencies need to be read up to 20,000 Hz or even 100,000 Hz for smaller aviation turbines.

Static strain is also important for turbomachinery. Slower measurements of strain (1-10Hz) are used to infer linear strain that changes with rotation speed or shaft power. This enables the characterization of blade disks, which much carry the centripetal load of up to 60 blades rotating at high speeds, generating tremendous radial loads.

As efficiency goals become more aggressive, reduction of disk mass is targeted. Strain gages can confirm new designs function safely over different speed and temperature regimes. Rotor shaft tension in the axial direction can be measured with strain gages, and shaft power can be inferred from looking at the strain in the circumferential direction of the surface of the shaft. These applications require the wiring through multiple blade disks and along the rotating shaft. But wire breaks and changes in line impedance can cause loss or drift of measurement values.

Dynamic strain signal conditioners power the sensors and read their resistance changes. New vendors have strain sensors and signal conditioners available now for less than $200, but many in the turbomachinery industry report that these less expensive options simply don’t work, or are unreliable at this time. Staid suppliers of dynamic and static strain gages and signal conditioners are currently the suppliers that most Instrumentation Engineers trust. Those gages can range in price from $40 to $200 each, and the signal conditioners are typically $1,500- $3,000 each. While these prices are not low, they pale in comparison to the cost of installing the strain systems on rotating equipment. To mitigate this, some attempts have been made to perform optical wireless measurements of strain on rotating blades and disk. Differential Speckle Photography and other systems have been attempted with varying success.

A recent addition is Digital Image Correlation, which is coming down in price. It uses stereoscopic cameras to view a sample as it changes over time, and directly measures strain in a non-contact method by comparing the positions of the minute surface variations over time. Two cameras are usually necessary. However, no robust versions are commercially available for use in the harsh environments of turbomachinery.

Wireless static strain gages offer an alternative. They are conformable and can be shaped to fit snugly onto rotating parts, with an effective conformability radius of less than 3 cm. They report strain by resonating at different frequencies and can be read from 5 cm at high rotation speeds. They are limited to temperatures of less than 150°C and can only be read up to 10 times per second. This is a limitation of the electronics, not the system; electronics systems are under development to enable true wireless dynamic strain. 

Joshua McConkey is Chief Technology Officer at Sensatek Propulsion Technology, a maker of wireless strain gauges and passive wireless RF sensors.

Reamonn Soto is CEO of Sensatek Propulsion Technology. 

For more information, visit www.sensatek.com or call 850.321.5993

Measuring rotating temperature and strain in gas turbines. 

Turbine Sensors

Solar Turbines, a Caterpillar Company, has been a mainstay of the turbomachinery landscape for many decades. It offers a wide range of products including centrifugal gas compressors and packages, mechanical drive packages, and gas turbines for oil & gas and power generation. 

It offers a series of gas turbine lines such as the Titan, Taurus, Mars, Mercury, Centaur, and Saturn. These range from 1 to 23 MW. Solar dominates the market for small gas turbines.

Solar Turbines has been providing solutions for Hydrogen (H2) rich fuels since 1985. It has logged over two million hours of operation, some units today using as much as 80% H2 content. 

H2 in gas turbine operation enables carbon reduction opportunities across a broad range of applications and industries. This will become increasingly more important as renewable penetration rises and gas turbines are needed to provide stable baseload and renewable support. 

“Increased global usage of H2 is needed to meet increasing energy demands from customers as well as carbon reduction targets set by companies and countries,” said Wade Willden, a spokesperson for Solar Turbines. “Solar is committed to continue increasing our H2 capabilities and investing in H2 technology, offering energy solutions that are clean, safe and reliable.”

Within pipeline gas applications, H2 will displace some portion of the natural gas in the pipeline. It is expected that the H2 content of the gas will not exceed 20% in the near future. But within the industrial process market, H2 content is already greater than 20% and as high as 100%. This market may include fuel gas with significant levels of other gases than methane, leading to careful consideration of safety, especially for high carbon monoxide. The best candidate today for this market and fuel type is a conventional combustion system.

Solar has extensive experience in high H2 technology. It has 46 generator set packages operating currently with nearly two million hours of accumulated experience and up to 65% H2. Of further note is a propane dehydrogenation application in Belgium that can operate with up to 83% H2. The company also has H2 experience in refineries with over 40,000 hours and up to 37% H2 in a conventional combustion system. 

Solar’s SoLoNOx dry low emissions combustion system can use fuel with H2 content of up to 20%. Examples include refineries in the United States and chemical plant applications in both China and Europe. 

Solar’s gas turbines, packages, and compressors are available for H2 fuel blends for both conventional and SoLoNOx combustion. The company is committed to supporting the industry with a development program leading to 100% capability on SoLoNOx by 2030 or earlier. 

It should be understood that the percentage of H2 blended with natural gas can have an impact on the gas turbine’s emissions signature. For conventional combustion, the impact on NOx emission varies by the percent of H2 and the presence of other fuel constituents. It must be be determined on a project-by-project basis. For SoLoNOx combustion systems at the 15 ppm NOx (and higher) warranty level, H2 concentrations up to 20% should not impact the emissions warranty.

Solar Turbines provides support for customers to ensure success with package upgrades, controls retrofits, and engine and compressor modifications for hydrogen-blend operation. In addition, Solar’s Fleet Assessment Services (FAS) provide a consultative assessment and recommendation for hydrogen blend and carbon reduction fleet opportunities and asset optimization.

Hydrogen is top of mind at Solar Turbines, a mainstay of the turbomachinery industry for decades. 

Vendor Spotlight: Solar Turbines

In the last 10+ years there has been a significant increase in the technology and instrumentation used on dry gas seal systems to monitor the condition of the seals. Most notable has been the call to monitor secondary seal condition – there have been significant failures of the secondary seal without any issue with the primary seal. The majority of these failures have been due to oil migration across the separation seals. As the oil is not drained out, it accumulates around the secondary seal, fills the grooves, and causes the secondary seal faces to contact. 

There are various approaches to monitoring secondary seal condition. Probably the most beneficial is utilizing a back pressure control valve in the primary vent (Figure 1). This sets the primary vent at a pressure below the primary seal gas supply pressure, but high enough for the user to be able to set a low-pressure alarm and trip (if required), indicating the secondary seal has failed. This pressure should probably be set somewhere between 15-25 psig, as this will provide a good differential pressure across the secondary seal and improve its lifespan by slightly increasing the gap between the faces (less wear). 

By using a positioner (wireless positioners are available) on the back pressure control valve, a user will be able to be proactive in determining if the secondary or primary seal is going to fail. For example, if the valve is normally set at 60% open and it starts to open more, this could indicate excessive primary seal leakage (assuming if intermediate nitrogen is being supplied, the flow has not increased). Likewise, if the back pressure control valve begins to close more, this could indicate excessive secondary seal leakage. 

By trending the position of this valve, one can predict at what point the valve will no longer be able to control the pressure. If the valve position stays relatively steady throughout a run on a compressor, it is not recommended to change the dry gas seals. However, if it has changed by more than 20% over a run time, it would be recommended to do so

Dry gas seals

Centrifugal compressors lie at the heart of oil and gas and industrial operations. They represent one or the most vibrant areas of the turbomachinery landscape and are supported by a thriving vendor community. These include Baker Hughes, Howden, Siemens Energy, Elliott Group, Atlas Copco Gas & Process, Kobelco, Mitsubishi Compressor, Man Energy Solutions, Ingersoll Rand, and Sundyne Let’s hear from each of them concerning the latest trends, products, and services.

“The energy supply chain, including natural gas and hydrogen, requires varying levels of compression, depending on the type of gas and the application,” said Leonardo Baldassarre, Executive General Manager, Engineering, And Platform Leader, Compressors, Pumps And Expanders, Turbomachinery & Process Solutions, Baker Hughes. 

Accordingly, Baker Hughes provides centrifugal compressor and pumps as well as reciprocating compressors. Its portfolio spans from horizontally split machines to barrel type. They can range from almost atmospheric compressors to very high pressure (up to more than 820 bars for centrifugal or above 2000 bars for reciprocating compressors) and from a few hundred cubic meters per hour to several hundred thousand cubic meters per hour flow. They can also accommodate any type of gas, from H2 to heavy refrigerating gases and from almost inert gases to very corrosive ones. 

For example, the Baker Hughes High Pressure Ratio Compressor (HPRC) is a high-speed rotor-compressor with a small footprint and high-performance stages for various applications, including hydrogen. These compressors can spin impellers at very high speeds, thus reaching high pressure ratios while handling very large flows.

“Today, we are working to leverage this architecture to increase impeller tip speeds, particularly for H2,” said Baldassarre. “This requires the development of high strength alloys coupled with an aero and mechanical impeller design aimed to minimize stresses.” 

Typically, components are tailored to customer needs and applications. The OEM designs each compressor with a mix of custom and standardized components for a specific plant and for a specific gas composition, flow, and pressure. 

In addition, the company is focusing on how to maximize the use of any energy cascade through optimized bottom cycles like sCO2. Another area of attention is connected to energy storage either associated with compressed gas or with batteries.

Siemens Energy offers: Single-shaft centrifugal compressors with features such as: dry gas sealing systems; up to four process stages; up to 10 impellers per casing; intercooling, side streams, and extractions; standard oil lubricated or active magnetic bearings; optional adjustable inlet guide vanes (IGV); and ultra-low temperature service. 

Pipeline compressors with features such as: Flange sizes (20’’, 24‘’, 30’’, 36’’, 42’’); max inlet flow rates of up to 106,700 m³/h); maximum working pressure of up to 2250 psi; Up to five stages; and a maximum power rating of up to 75,000 BHP / 56 MW). 

Custom-designed compressors covering performance requirements outside the above ranges such as those required for compressor head stations and natural gas storage and withdrawal operations.

Integrally geared compressors: Multi-shaft machines (several pinion shafts with two impellers each are arranged around a central bull gear). For each pinion shaft a combination of shaft speed and impeller size must be realized. All impellers are of overhung design and can be fitted with adjustable inlet guide vanes in front of each impeller. Inter-stage cooling of the gas stream can be done after each impeller discharge. The combination of these features allows for high volume flows, energy efficiency under part load, and a compact design. For small- to medium-size compressor sizes, Siemens Energy offers a package design. The package includes the compressor, driver, process gas coolers, lube oil console, process piping, and all tubing and wiring. This design leads to reduced on-site installation time. For large-size units, all main train components are delivered separately on site and installation is on a concrete foundation. 

The RF compressor product line, for example, is strong in the midstream pipeline market and comes in a variety of frame sizes. They are available in beam-style (RFBB) and axial inlet (RFA) configurations. Components such as casings, bearings, shafts, dry gas seals, and the interface with package hardware are standardized. The flowpath is customized for each project’s specific process conditions to achieve high efficiency. The RFA model’s single impeller design limits internal flowpath losses. The VIGV option is also available to change the operating map as process conditions change. Another feature is single dry gas seals; this feature can cut fugitive emissions in half compared to the standard bearing design. 

The company is seeing three major trends in the market right now: decarbonization; methane reduction; and standardization. With the focus on decarbonization, there is more attention being given to train efficiency because it has a direct impact on compressor efficiency: a more efficient compressor burns less fuel. For methane reduction, using dry gas seals with the RFA compressor model can slash primary vent leakage. 

“We also offer a capture and recompression solution, which is more economical with the RFA model due to low leakages,” said Scott Tackett, Sales Director, Midstream Compression for Siemens Energy Industrial Applications Business.

MAN offers a wide range of horizontally and vertically split centrifugal compressors, radial isotherm compressors, gear-type compressors, and integrally sealed compressors. 

MAN’s High-Speed Oil-Free Integrated Motor compressor (HOFIM) has a high-speed motor, driving a one or two multi-stage centrifugal compressor levitated by active magnetic bearings. The unit is hermetically sealed and encapsulated. Due to the modular concept, it provides flexibility in component and process configuration. Components usually seen on conventional topside compressor solutions such as gearbox, lubrication oil system, instrumentation, and valving are not required. This results in a compact design that facilitates fast installations. The motor power has a range from 1 to 18 MW, depending on which frame size it is used.

HOFIM units are used in subsea compression applications as well on platforms, or onshore applications. The technology is also used in the electro-thermal energy management system MAN ETES (Electro-Thermal Energy Storage). MAN ETES is a tri-generation energy management system that uses i.e., surplus renewable electricity to generate heat and cold for storage in insulated reservoirs. For this use case, the electrothermal process allows the distribution of the generated heat and cold to users according to demand and margins, but also offers the option of converting it back into electricity. The HOFIM compresses the CO2 working fluid to its supercritical state at 140 bar and around 120°C.

MAN has delivered two subsea HOFIM units for Equinor’s Åsgard subsea compressor station in Norway. Since operation start in 2015, they have performed with an availability of above 99%. “Subsea compression requires an extremely reliable remotely operated compressor on the seafloor,” said David Kodz, Solution Manager Subsea & Unmanned Compression + ETES at MAN Energy Solutions. “The compression unit is qualified for wet gas operation and significantly reduces the process complexity by eliminating liquid separation. The technology allows for fully remote and unmanned operation.” 

Beyond subsea, MAN operates in many other markets. In CCUS, MAN supplies the compression technology for purifying CO2 and storing the CO2 in a depleted oil field or a saline aquifer. It also operates in liquid air energy storage (LAES) and molten salt energy storage (MOSAS).

Atlas Copco Gas and Process provides both integrally geared and non-geared centrifugal turbocompressors for hydrocarbon processing, power generation (both renewable and conventional), and industrial gases. The integrally geared compressors cover pressures up to 205 bar (up to eight stages), flows up to 500,000 m3/h, and have maximum input power of 35 MW. The Compander is also integrally geared: Here compressor and expander functionalities are installed on one single gearbox and skid. The Compander is used in many hydrocarbon processing applications, including small-scale LNG, chemical/ petrochemical, as well as supercritical CO2. 

For the non-geared compressors, Atlas Copco Gas and Process provides solutions for polyolefines and main air, respectively. These compressors for PP/PE handle flows up to 65,000 m3/h, with a maximum input power of 10 MW and maximum pressure of 45 bar. The company’s non-geared compressors for main air handle flow volumes of up to 500,000 m3/h, with a maximum input power of 30 MW.

“The overarching trend in the industry is decarbonization, which impacts many areas of centrifugal compression and is driving advancement,” said Ulrich Schmitz, Atlas Copco Gas and Process.

For hydrogen transportation, the company already has a cryogenic (-253°C) integrally geared compressor solution for hydrogen carrier vessels. For applications where the hydrogen content is 100% and the gas is non-cryogenic, compressor suppliers are focusing a lot of their R&D efforts on developing efficient compression technology, said Ulrich Schmitz, Marketing Manager at Atlas Copco Gas and Process.

Elliott Group provides the following centrifugal compressor lines:

Single-Stage: Elliott’s TC and PH compressor product lines are single-stage overhung compressors. Their typical application is in services that require lower head requirements than that of a multi-stage between-bearing compressor. The low maintenance design with axial flow inlet and ability for rear pull rotor removal make these compressors a good fit for processes in dirty and corrosive applications such as petrochemical plants, refineries, natural gas processing, coal gasification, and ethylene oxide/ethylene glycol (EOEG). To further expand peak operating range, adjustable inlet guide vanes can be installed to improve performance for changing conditions or partial load operation. Single-stage compressor designs are standardly available with inlet flows up to 90,000 ACFM and an 800 PSI discharge rating.

Multi-stage: The M and MB compressor product lines are between-bearing centrifugal compressors. They are typically used in hydrocarbon markets including oil & gas production and processing, petroleum refining, petrochemical processing, cryogenic refrigeration, and industrial gases. Elliott’s M line of compressors are horizontally split while the MB product line is a vertically split configuration. M-line compressors are typically applied for lower pressure and fouling services. The MB-line is better suited for high pressure and clean gas service. Both of these compressors share major components of rotor design, bearing and sealing options, and aerodynamics staging, ensuring reliability. While utilizing many standard components, each is engineered to order based on customer specifications to optimize aero performance, rotordynamics, and reliability. Elliott Group’s M and MB line of compressors provide compression solutions for inlet flows from 1700 to over 850,000 acfm and pressures up to 10,000 psi.

The EDGE M-line compressor is the most commonly applied compressor in Elliott’s product line. This model is available in 15 standard frame sizes. The horizontally split casing makes this compressor a good fit for dirty, corrosive or fouling services that provide maintenance challenges to vertically split compressors. The frame size uses standard casing and endwall designs, while the aerodynamics components are custom tailored to the application. The EDGE compressor design uses a fully scalable aerodynamics flow path to allow scaling across all frame sizes. Stage line ups are available in straight through, sideload, isocooled, back-to-back, and double flow configurations. Advances in stage and nozzle design have increased flow coefficients beyond 0.25 and increased capacity per frame with the largest double flow compressor capable of volume flows in excess of 850,000 cfm. M-line compressors allow end users to achieve greater capacity without the typical frame increase of previous generation compressors without negatively impacting reliability or serviceability.

“Bearing and seal systems are being improved to reduce fugitive emissions and reduce or eliminate lubricating oil,” said Ronald Josefczyk, Director of Global Engineering for Engineered Products, Elliott Group. 

He also noted that many processes are focusing on casing and footprint reduction. Single large trains of equipment have lower efficiency losses per volume and points for fugitive emissions than parallel compressor configuration. Further, Elliott continues to extend the flow capacity of its product lines through full 3D high-flow stage design facilitating economy of scale improvement.

MHI Compressor Group manufactures and services API 617 beam-style and integrally geared (Part 2 & 3) centrifugal compressors at its Hiroshima, Japan and Pearland, TX facilities. It offers a range of custom designed compression varying from low pressure / high flow compressors (horizontally split) to high pressure / low flow compressor (vertically split). This includes upstream, such as FPSOs and CO2 reinjection, to mid and downstream in NGL processing, LNG, ethylene, ammonia, propane dehydrogenation (PDH), carbon capture, refining, and power generation.

“Globally we’re seeing a rise of energy transition related projects that support various decarbonization objectives,” said Clayton Jurica, MHI Compressor.

In addition, the company is strong in syngas compression. Synthesis gas, a relatively low mole weight gas mixture, plays a key role in many petrochemical plants such as ammonia and methanol. Based on the low mole weight and compression ratio capabilities, there is a requirement for many stages of compression, sometimes handled in multiple compressor bodies along with intercooling, in order to provide adequate discharge pressure and temperature for the overall process requirements. In North America, the company reports positive momentum on several blue ammonia projects in which the owner intends to export the ammonia to utilize as a fuel or as a carrier for hydrogen. There is also more interest in energy transition and decarbonization.”

“This covers the entire energy value chain such as carbon capture at new and existing facilities as well as plants utilizing electrolysis, Autothermal Reforming (ATR), and/or Methane Pyrolysis to produce hydrogen and ammonia,” said Clayton Jurica, Director of New Unit Equipment at MHI Compressor International.

he Ingersoll Rand Turbo-AIR and MSG integrally geared centrifugal compressor product lines provide flexible, high-performance oil-free compressor technology for industries powered by air or gas. Since they are oil-free, they are a good fit for industries that need to avoid oil contamination for product safety or quality. They are equipped with features to reduce energy expenditure and other costs.

Maestro Controllers continuously optimize the operation of the compressor by monitoring operating parameters and adjusting discharge pressure and outlet flow to match the user’s demand for a given application. 

Non-contacting seals ensure energy efficiency does not diminish over time. 

A pinion bearing, gear design and stainless-steel compression elements deliver durability.

“The cost of power over the life of the compressor will dwarf the capital cost in most cases,” said Sam Gooldy, Ingersoll Rand.

For example, the Ingersoll Rand MSG TurboAIR NX 5000 is an oil-free air and nitrogen compressor that provides optimized energy efficiency and operational flexibility. It generates oil-free air or nitrogen that meets IS0 8573-1 standard. The VIGV design enables a 35% turndown range, enabling it to be used in various demand scenarios to compress air or nitrogen for a process. During periods of low or fluctuating demand, the operator can adjust production without the need to shut it down or deploy energy-wasting blow-off.

While reliability measured in decades as an absolute, we see today’s compressor owners focus more and more on efficiency as the first among equals. As power costs seem to be on a perpetual march ever higher, we don’t see this changing any time soon.

Sam Gooldy, Senior Global Product Manager at Ingersoll Rand, said that a couple of years ago, a typical 7,500 cfm compressor discharging at 125 psig would require about 1500hp of power at full flow. The Turbo-AIR NX can achieve that same flow and pressure, but it only consumes 1400hp.

The Howden Centrifugal Compressor group includes brands such as Turblex, HV-Turbo, Kühnle, Kopp & Kausch, Bryan Donkin, CKD, and Roots. Each brand offers single-stage and multi-stage centrifugal turbocompressors. Dual vanes are available on many of the single-stage models, and several have the option for both inlet guide vanes and variable diffuser vanes for process power optimization. A few typical applications include process air for environmental processes like wastewater, combustion air, compression for sulfuric acid plants, mechanical vapor recompression (steam compression), and process gas compression. These models can be configured to meet API-617 and API-672 specifications.

he Roots OIB single-stage centrifugal compressor, for example, has its beginnings in the early 1930’s. It can handle a wide range of applications from standard industrial to high specification API type process requirements. The OIB standard design features hydrodynamic tilting pad radial bearings and a double acting tilting pad thrust bearing along with a variety of seal options.

According to David C. Hokey, Howden Roots Turbo Product Leader, many companies are exhibiting interest in digital solutions for plant equipment partly due to the need for crews to look ahead to schedule maintenance.

Howden Uptime serves the need for digital services such as the digital twin. Using physics data on how customer equipment operates and responds to the environment, as well as data provided by the sensors, the digital twin is used to analyze and simulate real world conditions, including response to changes, and how to improve operation.

Sundyne offers four different centrifugal compressors. These are single- and multi-stage designs for API 617 as well as fit-for-purpose applications in oil & gas production, natural gas processing, power generation, hydrocarbon processing, and chemical processing. Each model is custom-built to provide pulsation- and vibration-free operation, and to deliver oil-free process gas with zero emissions. 

The Sundyne LMC vertical integrally geared process gas compressor is a fit-for-purpose design that offers single-stage compression with: Flows to 3,550 acfm (6,000 am³/hr); maximum working pressure 1,440 psi (100 bar); maximum Speed: 34,200 RPM; temperature range -200 to +500oF (-130 to +260 o C); and a design that is 25% the size of reciprocating, barrel, or rotary screw compressors. 

The Sundyne BMC integrally geared process gas compressor is an API 617 horizontal single-stage compressor that provides: Flows to 3,550 acfm (6,000 am³/hr); maximum working pressure 1,440 psi (100 bar); maximum speed: 34,200 RPM; and a temperature range of -200 to +500oF (-130 to +260 o C). 

The Sundyne LF 2X80 base mounted integrally geared multi-stage process gas compressor can be outfitted to meet API standards or engineered as a fit-for-purpose compressor. It has one-to-four stages of centrifugal compression on a single gearbox and delivers: Flows to 6,000 acfm (10,200 am³/hr), maximum working pressure 1,440 psi (100 bar); maximum speed: 32,000 RPM (60 Hz), 32,000 RPM (50 Hz); and temperature range of -200 to +500oF (-130 to +260 o C).

The Sundyne LF 2000 API 617/ISO 10439 base-mounted, integrally geared, multi-stage process gas compressor is API-compliant. It features one-to-six stages of centrifugal compression on a single gearbox, providing: Flows to 10,000 acfm (17,000 am³/hr); maximum working pressure 5,000 psi (350 bar); maximum speed of 42,000 RPM (60 Hz), 42,000 RPM (50 Hz); and temperature range -200 to +500oF (-130 to +260 o C).

The Sundyne LF 2000 multi-stage centrifugal compressor (known as a Pinnacle) has been deployed for midstream, hydrocarbon processing, and chemical manufacturing applications. This includes fuel gas boost for power generation, hydrogen recycle, mole sieve dehydration, regeneration of demethanizers, waste gas, and specialty chemical production. Its horizontal configuration features a modular baseplate that simplifies skid packaging and installation. Packaging and instrumentation are customizable. Sundyne Pinnacle machines are built to run continuously for up to 7 years without interruption. These machines are being deployed as feed gas compressors for amine scrubbing applications to reduce CO2 from flue emissions. With Amine scrubbing, CO2 and other sour impurities in the gas require stainless steel or NACE-compliant corrosion-resistant materials. Flash conditions due to heating and cooling processes require high head. Pinnacle compressors meet these requirements.

he company has observed an increase in inquiries and business for single- and multi-stage compressors in transportation of green hydrogen (with producers in the Middle East and Africa with large solar infrastructures), cleaner synthetic fuels and feedstocks (with companies in Europe to process hydrogen), CO2 and methanol to make fuels for industrial vehicles and cleaner feedstocks for chemical manufacturing. Finally, Sundyne expanded its testing facilities to mimic the specific manner in which a machine will operate once it’s deployed.

The latest products, services, and trends including hydrogen compression, carbon capture, and bigger machines. 

Centrifugal compressors in Oil & Gas

Real-world operational turbomachinery problems can be challenging. Fast decision making is often required. The questions such as “what to do now?” and “how do we deal with this issue?” during live operation can be difficult to answer. It is important to be prepared.

Temperature limits inside a compressor are dependent on compressor design, material selection, and component manufacturing and process gas properties. Mechanical considerations usually differ from compressor to compressor. As a rough indication, temperature limits associated with mechanical design could be about 210°C. However, sealing elements and non-metallic components might limit the gas temperature to around 175°C. But some gases should be kept lower than these temperatures based on process requirements. 

For example, polymerization could be a concern for some gases. If gas temperature passes the limit, polymerization can result in fouling or unbalance masses on impellers which could cause performance deteriorations, long-term vibration, and operational problems. For some process gases, the process limit on temperature could be somewhere between 80°C and 140°C.

A centrifugal compressor with a high flow side-stream was located at the downstream of a complex gas drier system. The side-steam flow was around 3.5 times the main suction flow. During operation at night, a malfunction in the gas drier system raises gas temperature around 40°C compared to normal operation. The compressor experienced a sharp increase in suction temperature. As a result, compressor vibration increased by around 10%, requiring operation team and machinery engineer attention.

A large flow of gas with a relatively low temperature came from the side-stream nozzle and cooled the compressed gas at the mixing section inside the compressor. The suction temperature sharp rise caused an increase of about 9°C at the discharge. Gas temperature increased at the discharge of the first section (before the mixing section) inside the compressor.

Based on measured data, operating parameters were not beyond limits except for the suction temperature. However, there was a concern about high temperatures inside the compressor. An operator recommended tripping the compressor to prevent damage due. The trip was not approved by the machinery engineer and the shift operation leader. Their assessment was that the internal temperature had not passed the limit and any trip could cause a thermal shock in the compressor internals. It would also interrupt production. The operations team acted quickly and corrected the problem in the gas drier system within seven minutes. Suction temperature and vibration levels returned to normal with no sign of damage or malfunction. Additionally, it was confirmed that process gas was not polymerized.

The lesson learned from this event: When the side-stream flow is considerably higher than the main flow, the suction temperature alarm requires careful attention since there could be a possibility that internal temperatures reach a high level and pass the limit while the final discharge temperature may only show a small rise due to the cooling effects of the incoming large volume of side-stream flow.

For an alarm case when all operating parameters are still within allowed limits, the general recommendation is not to shutdown machinery. In the case of increased gas suction temperature for a short time when no parameter passes its limit, the recommendation is to continue operation unless there is a reasonable evidence of the need for a shutdown.

Real-world operational turbomachinery problems can be challenging. Fast decision making is often required. 

Turbo Tips: Tackling real-world challenges 

With the onset of the hydrogen energy economy, and the significant cost and logistical advantages of blue hydrogen (hydrogen derived from fossil fuels with carbon sequestration) over green hydrogen, comes the need for added new compression of carbon dioxide (CO2) from hydrogen production for transport and sequestration injection. 

Every pound of blue hydrogen produced through steam reforming or partial oxidation gasification creates about 10 pounds of CO2. This CO2 must be compressed from near atmospheric conditions to pipeline operating pressure. It then must be transported in the pipeline, and finally compressed to geological formation storage pressures for long-term sequestration. Compression is also required for CO2 derived from power plant post-combustion flue gas separation. The pressure of CO2 gas from this process depends on the type of separation process used and can vary from slightly above atmospheric to several hundred psi. 

In addition, there is significant uncertainty about the injection pressure required by the geological formation since it is contingent on the type of formation and its drilled depth of injection. A generally accepted rule for storage in geological formations is that for every mile of depth of injection, about 1800 psi of gas pressure is required. Since many of the geological formations considered are relatively shallow, injection pressures well below 2000 psi are often sufficient. 

Thus, carbon capture and sequestration in most power plant applications require these new compression duties:

Compression from the separation processes (membrane, thermal or chemical) to pipeline pressure.

Injection for sequestration storage in a geological reservoir.

Further, new power plant cycles such as sCO2 cycles, or oxy combustion, are gaining acceptance. The generally accepted industry convention for CO2 transport is that CO2 should be transported as a supercritical fluid in pipelines at 2000-2200 psi operating pressure. At 2000 psi, CO2 is well above its critical point in a supercritical (dense phase) state for all ambient temperatures. Fluids in a dense phase share both some physical properties of liquids, such as very high density, and of gases, such as compressibility (albeit very low) and the fact that they expand in space to fill voids.

Every pound of blue hydrogen produced through steam reforming or partial oxidation gasification creates about 10 pounds of CO2.

The advantage of transporting CO2 at supercritical pressures is its very high density and low viscosity, allowing for efficient transport. This significantly reduces the power demand for the pumping or compression stations along a CO2 pipeline. The disadvantage of operating at these high pressures is the added compression ratio required at the pipeline header station and the significantly higher costs for materials to build a pipeline designed for maximum allowable operating pressure well above 2100 psi. This also means that very few natural gas pipelines can be converted for CO2 transport.

However, transport at 2000 psi is not required for all applications. The actual transport pressure of CO2 depends on the separation process outlet pressure, the distance the CO2 must be transported and the geological sequestration injection pressure (often well below 2000 psi). Since the CO2 available from separation is usually at low, near atmospheric pressures (<100 psia), the pipeline header station must always use a compressor.

Specifically, a 2000 psi CO2 pipeline requires a high-pressure ratio header compressor with many intercooled stages that can handle the significant volume reduction. But for this case, in the pipeline beyond the header station, the gas is transported in dense phase, either by pump or by compressor. On the other hand, if a lower pressure CO2 pipeline is used, conventional compressors are preferred for the header station and re-compression along the line. Clearly, selection of transport pressure depends on the carbon sequestration application, but it is not always advantageous to go to the pressure needed for a supercritical CO2 pipeline.

In general, CO2 is a heavy gas that is relatively easy to compress with centrifugal compressors from a compressor stage thermodynamic perspective. But it presents some other technical challenges that need to be addressed to make the overall compression or pumping process efficient and reliable:

Most equations of state for CO2 and CO2 mixtures are inaccurate at high pressures and temperatures. 

Even in dense phase, CO2 is compressible. 

CO2 is a heavy gas that results in amplified rotor dynamic and impeller dynamic forces, and it has strong thermodynamic path dependence and multi-phase behavior. 

Carbonic acid is formed in the presence of water, driving corrosion, and CO2 is soluble in elastomeric materials, which can lead to rapid decompression failures. It selectively leeches certain elements from common metals. 

When rapidly expanded, CO2 quickly forms liquids and dry ice, which can become a potential problem for shaft seals. 

Aerodynamic concerns come from its low sonic speed, which can result in high Mach numbers, causing shock losses and a reduced operating range.

Proven machinery solutions for compression and pumping of CO2 are commercially available. Nonetheless, it is still important to be aware of these issues and to recognize that CO2 compression and pumping comes with technical challenges that must be individually addressed for all new carbon sequestration technologies.

Myth: Carbon dioxide is always pumped

Turbomachinery International visited Jeanette, Pennsylvania to witness the opening of Elliott Group’s new $60 million cryogenic pump test facility. Construction on the Cryodynamic Products testing facility kicked off in December 2019. The ribbon cutting ceremony took place in late October, 2021. It included industry representatives as well as county, local, and company officials.

The speakers were: Toichi Maeda, Chairman and Director, Ebara Corp., parent company of Elliott; Curtis Antoniak, Mayor of Jeanette, PA; and Mike Lordi, CEO Elliott Group, who ended the formalities with a toast.

The new complex includes six buildings, with about 30,000 sq. feet under roof on the 13-acre campus. It will generate approximately 100 jobs. The test loop features two cryogenic pump test stands and a dedicated cryogenic expander test stand. As it is indoor and enclosed, weather conditions have no impact on testing.

"We can test a full range of cryogenic pumps and liquid expanders, from the smallest units, to units larger than those currently available in the industries we serve,” said Mark Babyak, Vice President of Cryodynamic Products and Industrial Products at Elliott. “We can test units with liquid nitrogen, natural gas, or propane, depending on their specific application, and we’re equipped with the latest instrumentation technology."

The facility has its own dedicated 25 kV electric utility service, a 25-ton crane with a 10-ton independent auxiliary hook, an energy-efficient cooling system, vacuum-jacketed insulated piping, redundant in-line heat exchangers, vessel-mounted tube bundle heat exchangers, and insulated vessels. In addition, its liquid storage tank farm houses a 60,000-gallon liquid nitrogen (LN2) tank, a 60,000-gallon liquefied natural gas (LNG) tank, and a 36,000-gallon liquefied petroleum gas (LPG) tank.

There are two cryogenic pump test stands. Test train 1 has three vessels (two pump and one dedicated to expander testing) with a maximum pressure of 2,160 psig and a maximum flow of 4,000 M3H. It has a 5 MW medium-voltage drive (range of 2,300 to 6,900 volts) and a 1 MW low-voltage drive (380 to 690 volts). 

Test train 2 has two pump vessels with a maximum pressure 3,600 psig and a maximum flow of 1,300 M3H, as well as medium- and low-voltage drives with the same specs as test train 1.

The dedicated cryogenic liquid expander test stand has an easily configurable test loop, standardized loop designs for upward or downward flow, and can test pumps while setting up the expander test loop. Its modular piping design can deal with inlet pressures up to 2000 psig.

Babyak said a few pumps had been tested as trial runs and that the facility would shortly go into full production. On the agenda are major tests for pumps and expanders destined for LNG projects around the world.

“We can test both column-mounted and vessel-mounted units,” said Babyak.

The company’s previous testing facility was not completely enclosed so weather such as strong winds often delayed tests. Further, only one test loop was available. Now with two test loops, Elliott can carry out lengthy setup procedures for one test while another test is ongoing. That means far more tests can be done, the size of unit that can be tested has doubled, testing times are decreased, and delivery schedules can be brought forward. The electrical load limitations of the older facility have also been eliminated.

“The size of liquefaction plants and expanders continues to grow,” said Babyak. “Hardly anyone else on the planet can conduct such tests, and our facility is much larger and more modern than any other.”

Turbomachinery International attended the ribbon-cutting ceremony in late October, 2021. 

November/December 2021