Klaus Brun is the Director of R&D at Elliott Group. He is also the past Chairs of the Board of Directors of the ASME International Gas Turbine Institute and the IGTI Oil & Gas applications committee. Rainer Kurz is the Manager for Systems Analysis at Solar Turbines Incorporated in San Diego, CA. He is an ASME Fellow since 2003 and the chair of the IGTI Oil and Gas Applications Committee.

Klaus Brun & Rainer Kurz

In part one of our two-part column on compressors for carbon capture and storage, we discussed the applications and design of reciprocating versus centrifugal compressors for a sustainable energy economy. For lower-flow carbon sequestration applications, reciprocating compressors have been the traditional base option over centrifugal compressors. In many cases, electric motor-driven reciprocating compressors are utilized. However, as the industry is rapidly moving toward much higher CO

 volume flow rates for large-scale carbon capture, the limits of the practical use of reciprocating compressors are being reached. We conclude our discussion on this topic with a look at compression challenges and the often overlooked, lesser-known disadvantages of reciprocating compressors for CO

 is generally considered a heavy gas with a molecular weight twice that of natural gas and 22 times that of hydrogen. As noted, this makes CO

 from a simple thermodynamic perspective, relatively easy to compress, but it presents other technical challenges that need to be addressed to make the overall compression or pumping process efficient and reliable.

For most carbon-capture applications, the compression process must cross the critical point of CO

 from the gas phase to either the liquid or supercritical dense phase. Therefore, it has strong thermodynamic path dependence and multi-phase behavior. Its physical properties vary considerably during the phase transitions, which makes aerodynamic design challenging.

 is a heavy gas, which results in amplified dynamic forces on any moving components. It has significant volume reduction and temperature increase with work input that results in the need for a wide range of flow coefficient stages (for centrifugal compressors), cylinder sizes (for reciprocating compressors), and multiple intercoolers. 

Carbonic acid is formed in the presence of water, which corrodes metal. At high pressures, CO

 also selectively leeches certain elements from common metals. 

 is soluble in elastomeric materials, which can lead to rapid decompression failures. Also, when rapidly expanded, CO

 quickly forms liquids and dry ice, which can become a problem by plugging dynamic and static seals.

Aerodynamic concerns come from its low sonic speed, which can result in high Mach numbers, causing shock losses and a reduced operating range. It also has a very low viscosity, which, while being beneficial from a pressure-drop perspective, can result in earlier boundary layer separation and increased secondary flows.

These issues apply to both centrifugal and reciprocating compressors, but reciprocating compressors have additional issues when operating with CO

. Some of the top challenges are pulsation control, leakage, flow control, and mechanical reliability.

Reciprocating compressors produce pressure pulsations that are induced into the piping system. These pulsations can cause acoustic resonance and mechanical vibration if they are not properly attenuated. This is especially true for dense gases, such as CO

, that amplify dynamic forces and are capable of transmitting pulsations over very long distances. Complex attenuation systems, including bottles, choke tubes, side branch absorbers, and orifices, are usually required to control these pulsations. Due to the low sonic speed and the high density of CO

, the reciprocating compression process injects strong periodic pulsations that result in high-amplitude acoustic resonances at low frequencies in the piping systems of the compressor station. 

Not only can these pulsations induce strong structural vibrations resulting in piping failures at these stations, but they can also travel miles down the pipeline causing noise and structural issues. It is therefore imperative to design the compressor stations with appropriate pulsation attenuation devices and resonance avoidance to eliminate the possibility of developing strong pulsations in the flow.

 creates several challenges, including a higher risk of pulsation and vibration problems than typical natural gas transmission stations. Current existing CO

 pipelines operate above the critical point between 1,200 - 2,200 psia to maintain single-phase operations in the dense-phase region. With a typical pipeline pressure of 2,100 psia at ambient temperatures, the associated density is around 60 lb/ft

, which is nearly equal to that of liquid water. Since density directly correlates to pulsation forces, this can cause significant issues with pulsations and shaking forces if the reciprocating compressor pulsations are not adequately attenuated. 

The other challenge to consider in compressing CO

 is its relatively low speed of sound. Acoustic natural frequencies in the piping system are determined by the speed of sound of the medium. Low speed of sound results in low acoustic natural frequencies in the system. When a resonance condition is created at low frequencies, the resulting pulsations can travel for long distances in the piping with lower attenuation than what is typically seen in higher-frequency pulsations and with lighter fluids. Pulsations traveling over hundreds of miles upstream or downstream have been observed in dense gases. Low-frequency excitations can also result in a strong structural interaction that has the potential to cause severe damage to the piping system, even at piping locations far away from the pulsation source.

Leakage control in reciprocating compressors is very difficult, especially over time as the sealing rings and packings degrade. Current packing technology uses a series of specific cut-dry ring seals held in place with springs and cups to seal the pressurized gas in the cylinder against the air at atmospheric pressure in the distance piece. Abradable packing seals made from polymers are commonly used to minimize leakage. These tend to wear over time, so leakage can become excessive unless they are frequently changed. Once the piston moves, the pressure differential across the packing seals creates a twisting effect on the seal, allowing significant amounts of process gas to leak into the casing and then out into the atmosphere. The leakage through this pathway increases even more with wear and increases (sometimes exponentially) with static hold conditions since the seals are primarily designed to activate with a moving piston rod. This is obviously very problematic for carbon-capture applications since the primary objective of the system is to capture and sequester as much CO

 as possible...not to leak it. As noted, when CO

 is leaked and/or rapidly expanded, it can form dry ice due to the Joule-Thomson effect, which can cause significant operational problems. Reciprocating compressors could easily become a major source of CO

 emissions from leakage. From a design perspective, it is difficult to completely eliminate a gas leakage path from the process gas cylinder to the piston rod. 

FLOW CONTROL, RELIABILITY, NOISE, AND LUBRICATION

Some other concerns with reciprocating compressor operation are flow control, reliability, noise, and lubrication. Flow control is challenging in reciprocating compressors since they are fixed-volume displacement machines that typically only operate over a limited speed range because of pulsation and vibration limits and exclusions. Flow control is usually handled using variable cylinder clearance volume, external pockets, and recycling. This not only means added operations personnel for mostly manual control, but also that with a reciprocating the operation of the pipeline is usually transient in that one is constantly packing and unpacking the line.

Reciprocating compressors are mechanically less reliable and require more maintenance than most other compressor types. This is due to their many moving parts and high-speed alternating linear motion that puts inertial cyclic stresses on most reciprocating parts. In a power plant, where operational uptime, high start-up reliability, and low maintenance costs are imperative to remain profitable, this is especially problematic. 

Reciprocating compressors create high levels of sound in a frequency range that is a major noise nuisance and very uncomfortable to human hearing. Unfortunately, because of the bulkiness and mechanical arrangement of these compressors with external moving parts, effective ambient noise control using sound-insulating blankets or enclosures is difficult. 

Finally, most reciprocating compressors operate using wet seals, which means that they continuously leak lubricating oil into the process gas stream from the lubricating film between the cylinder and pistons. Even with a well-controlled lubrication make-up system and an efficient downstream separator, some of this oil will carry over into the pipeline. This can become a significant issue for CO

 geological storage applications since oil contamination in the formation would cause an environmental and safety hazard (and when coke-hardened, may even plug injection lines over time). Alternatively, dry-operating reciprocating compressors could be used, but these are even less mechanically reliable than lubricated compressors.

This discussion is designed to present our perspective on the ongoing debate of reciprocating versus centrifugal compressors within sustainable energy economy gas compression systems. This is an ongoing industry debate that will obviously continue for a long time. We simply gave our opinion based on our engineering experience, and we are sure many will disagree with our assessment, but, regardless of the perspective, it is always important to clearly understand all the features, limits, advantages, and disadvantages of the different types of compressors for any given application when making critically important, long-term equipment and infrastructure decisions.  

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 Manager 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 & Gas Applications Committee.

Articles

Reciprocating compressors present challenges—such as pulsation control, leakage, and mechanical reliability—in CO2 capture and storage applications.

Myth Busters: Part II: Reciprocating vs Centrifugal Compressors for CO2 Capture and Storage: Challenges and Disadvantages

Much was made in the news about the greenhouse gas emissions (GHG) caused by last year’s Nordstream pipeline act of sabotage. Although these greenhouse gas emissions were certainly highly undesirable, the total amount of natural gas released was actually less than what is released on a monthly basis by some of the less concerned oil-producing nations. 

The Intergovernmental Panel on Climate Change has found that even if the world cuts emissions by the rate governments have promised, the goal to limit global warming to 1.5°C (2.7°F) around the year 2050 will still ‘more likely than not’ be missed.

In recent years, methane emissions have come into focus. Natural gas has a global warming potential that is about 20 to 35 times higher (depending on who you ask) than that of carbon dioxide, so there is justifiable reason to insist on the reduction of natural gas emissions, especially since they are a waste of a useful fuel source. Methane produces a stronger greenhouse effect than the same amount of CO

, but methane lasts in the atmosphere for only about one decade. This explains two things: 1) the wide range of multipliers for methane’s global warming potential and 2) the attractiveness of methane reduction, since (unlike CO

reduction) the effects of methane reduction will be felt much faster.

Natural gas’s principal constituent is methane which is considered a strong GHG. According to the U.S. Environmental Protection Agency, only about 30% of methane leakage in the U.S. is caused by the oil and gas industry. The rest is attributed to agriculture, landfill, and other mostly biological sources.

There are many avoidable, unavoidable, and accidental emissions points for methane in the oil and gas production and value stream, and there is significant misunderstanding about them among the public. Natural gas emissions from oil or gas production can be divided into accidental leakage, incomplete combustion (unburned hydrocarbons), and/or intentional blowdowns/releases. These emissions account for approximately 3-4% of total U.S. greenhouse gas emissions on an equivalent carbon dioxide basis but are potentially much higher in other oil-producing countries. To provide some clarity, we list the natural gas point leakage sources and discuss the potential for their reduction or elimination.


By far the largest segment of methane leakage in the oil and gas industry occurs in the upstream production process, which accounts for at least half methane emissions (according to some publications the number is substantially higher). The big three sources here are production venting, leakage, and gas gathering compression. While leakage and venting are mostly accidental or safety related and, thus, can be reduced through improved operations practices, leakage from gas gathering compression is more complex.

Gas gathering reciprocating compressors are a major source of methane emissions since it is difficult to eliminate a gas leakage path from the process gas cylinder to the piston rod. Abradable packing seals made from polymers are commonly used to minimize leakage. However, these tend to wear over time so that leakage can become excessive unless they are frequently changed. Several studies indicate that nearly a third of upstream methane emissions come from leakage through reciprocating compressor rings and packings. The majority of this leakage, as well as unburned hydrocarbon production, is associated with smaller upstream machines in gas gathering duty which are often operated in unmanned compressor stations with little supervision or control. More frequent maintenance and better condition monitoring could reduce this very significant source of methane emissions. But these requirements would add cost and could reduce availability. A viable alternative in many cases is to convert to centralized gas gathering compression stations using larger centrifugal compressors rather than many small units.

In midstream gas transportation and down-stream gas processing applications (including LNG production), most methane emissions are related to blowdown venting, valve leakage, and a smaller percentage to compressor leakage. Blowdown and venting may be reduced by better safety technology, reduced maintenance intervention, and blowdown avoidance devices. However, most of these events are compressor station safety driven and cannot be completely avoided. Reciprocating compressors in the midstream segment also leak but tend to be larger and better maintained than in the upstream segment.

Finally, centrifugal compressors are common in pipeline and refinery compressors. Their leakage is primarily caused when outdated wet oil seals are used. Modern dry gas seals on centrifugal compressors drastically reduce methane leakage. Because of this, few centrifugal compressor manufacturers still offer compressors with wet gas seals. Dry gas seal systems could certainly be improved since they are still somewhat sensitive to contamination and sometimes fail.


As noted, GHGs (due to facility blowdowns) are a significant contributor to the total industry GHGs. Blowdown situations may be caused by maintenance requirements related to safety or due to false sensor readings. Some of these could be eliminated using improved alarm/shutdown sensor systems, increased sensor redundancy, more frequent inspections, and generally through higher machine reliability. Also, few compressor installations utilize continuous measurement leak detection. But the technology, especially optical sensor based, is technically feasible and commercially available to a limited extent. Pressurized hold is a potential alternative to full station blowdowns for extended shut-down periods. But the equipment must be designed to stay in pressurized hold for extended periods of time and must be able to start from a pressurized hold. These decisions require a good understanding of plant safety and maintenance practices and improved operator personnel education. Finally, blowing down into low pressure gas storage tanks, or utilizing a thermal oxidizer (flare) rather than a cold stack for non-safety related shutdowns, should be considered to reduce methane emissions.

It’s also important to note the often-advertised conversion of natural gas to blue hydrogen does not significantly help to reduce methane emissions. In almost all cases, the blue hydrogen is produced at the back end of the oil and gas value stream, i.e., all methane losses are already incurred in the process by the time of the gas conversion.

Technologies exist to reduce methane emissions of centrifugal compressors to zero. Modern centrifugal compressors with dry gas seals avoid uncontrolled methane emissions, so the methane leakage can be gathered and recompressed back into the pipeline. The technologies exist and are commercially available. Furthermore, dry gas seals have been developed that avoid any methane leakage, but they would leak nitrogen. Some jurisdictions see nitrogen as a regulated leakage too, even though the atmosphere consists of 78% nitrogen, and nitrogen is inert under atmospheric conditions. While reciprocating compressor manufacturers are also developing technologies to prevent methane emissions, these may be more difficult and costly to implement.

Emissions from the energy industry are being regulated; since methane is valuable, the loss avoidance of methane in production, transport, and combustion also has positive side effects on the industry. One of the dangers is that relatively small contributors (such as the leakage from dry gas seals or the practically negligible unburned hydrocarbon emissions from modern gas turbines) are pursued with the same vigor as large contributors, thus slowing the effort. However, methane emissions are not the exclusive problem of the energy industry. The majority of methane emissions are produced by landfills and the agricultural industry.

Machinery emissions of methane are often a function of the amount of maintenance or safety interventions when methane must be blown down. Thus, the effort of the industry to use digital solutions to reduce shutdowns will also reduce methane emissions. Technologies that allow keeping units pressurized during shutdowns that are not maintenance-related are already in place.

This Myth Buster column went over the potential for methane leakage reductions from the natural gas energy infrastructure. The incentives are obvious. Leaked gas is revenue lost and green-house gas produced. But most importantly, to avoid future government environmental regulatory intervention, the industry should be proactive in voluntarily implementing as many of the above methane leakage reduction technologies as is technically feasible and commercially viable. 


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 Manager 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.

Debunking the myth on methane leakage in the oil and gas industry. Gas gathering reciprocating compressors are a major source of methane.

Myth: Methane Leakage Cannot Be Avoided

The latest buzzword in the turbomachinery industry is the digital twin. It’s being praised as the holy grail for everything from failure prevention and maintenance reduction to life extension, improved operation, and parts fore-casting. While the digital-twin concept offers defi-nite value for machinery operation, some of these claims stretch the truth. It’s worthwhile to discuss what a digital twin really is, what it can do, and where its limitations lie. 

A digital twin is a computer virtual represen-tation and simulation of a real physical object or process. Although the idea has been around for a long time, the basic concept and definition were introduced in 2002 by Michael Grieves, then at the University of Michigan, as a model for Product Lifecycle Management. NASA then coined the term in 2010 in a Roadmap Report. The digital twin consists of three parts: the physical object, the digital or virtual product, and the connections between the two. The concept has branched out into different types, such as the digital-twin aggregate (DTA), where multiple digital twins operate in parallel to simulate a complex system.

Implementing a simple digital twin or a more complex DTA requires data about the real-time status of the real-life object, as well as the ability to operate, maintain, or repair the real system remotely via a parallel digital twin representation. Think of Apollo 13, where the ground-based engineers were able to determine how to rescue the mission remotely by simulating all operations and failure scenarios to identify a viable solution. Thus, “the ultimate vision for a digital twin is to be able to create, test and build [our] equipment in a virtual environment” (John Vickers, NASA, 2010). 

In its purest form, the digital twin is a product and technology development tool. That means it is also an alternative to big data approaches, where correlation is assumed to be a proxy for causation. The digital twin is essentially a computer simulation program that uses real-life data to create simulations that can predict how a physical asset will perform. Artificial intelligence, self-learning, and software data analytics can also be utilized to enhance and refine the output. 

But, to quote Lewis Carroll’s Humpty Dumpty in Through the Looking-Glass, “When I use a word, it means just what I choose it to mean.” So, what does “digital twin” mean in current turbomachinery discussions about condition monitoring, predictive interventions, condition-based repair and process optimization? 

The distinction between a simulation model and a digital twin is not really clear. The basic components of a digital twin are a model and some real-life operational data. That’s nothing new. For decades, we have used performance models — in the form of performance curves or compressor maps, for example — to determine the health of equipment by simply comparing the expected behavior (from the curves) to measured performance data. The difference between a model and a digital twin (i.e., “a digital twin without a physical twin is a model”) does not help because the performance curves actually reflect the behavior of a real machine.

The added feature of a true digital twin versus a simple model is that a digital twin can adapt to changes of the physical object over time. For example, if a machine shows wear or has perfor-mance degradation, a true digital twin can adjust whereas a simple model simulation cannot. The digital twin thus provides added value in that it provides a more accurate representation of the current state of the machine. This can be of significant value when scheduling maintenance and repairs or predicting remaining life since the digital twin’s updated parameters directly relate to known physical failure mechanisms. 

One of the key insights of digital-twin operation is that the simulation model used in the background does not have to be complicated. The use of performance curves noted above can be part of a digital twin. But updating the model to the current state of the machine using measured data is not trivial. Measured data is always subject to condition, measurement, and statistical uncertainties. The digital-twin correction using actual data (from operations, field, and factory testing) must be treated as a statistical process — the more data, the better the model improve-ment. The sourcing of test data from multiple (more or less) identical machines helps signifi-cantly when correcting the model. This means that a manufacturer with a large number of machines in operation (gas turbines, steam turbines, compressors etc.) has an advantage when building a digital twin. 

The minimum requirements for the model used in a digital twin are simply that it is sufficiently physics-based, accurate, and quick to run. The concept of a digital twin, leaving all the hype aside, is based on existing and mature technologies. Overuse of the term may lead to underutilization when potential adopters become cynical of the buzzwords and shiny presentations. Using the concept requires trust in the model, the data, and the algorithms used to update the model. Supervision by human experts is still required for checking the plausi-bility of the model outcomes and digital-twin recommendations. 

■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.

Any views or opinions presented in this article are solely those of the authors and do not necessarily represent those of Solar Turbines Incorporated, Elliott Group, or any of their affiliates

The Digital Twin Knows it All  

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

Hydrogen is a colorless, odorless gas that burns with a near invisible flame. So why do we constantly hear about green, blue, grey and other colors of hydrogen? What are these colors for?

Hydrogen “colors” colloquially refer to the way the hydrogen is generated. We have a rainbow of colors including brown, grey and black that are not part of the rainbow. For the most part, turbomachinery that either utilizes or transports hydrogen doesn’t care where and how the hydrogen originated. But it is still important to understand the basic nomenclature.

 hydrogen is produced without any greenhouse gas emissions. It is made by using electricity from renewable sources, like photovoltaics or wind power, to electrolyze water. Electrolyzers use an electrochemical reaction to split water into its components, hydrogen and oxygen.

 hydrogen is produced from natural gas using a process known as steam reforming, where natural gas and steam react to form hydrogen, but also carbon dioxide. To make hydrogen “blue,” the carbon dioxide must be captured and sequestered. If the same process is used, but the carbon is not captured, it is called grey hydrogen.

 hydrogen are made through partial oxidation gasification from black coal or brown coal (lignite). This is the type of hydrogen that creates the largest amount of environmentally damaging by-products.

) hydrogen is generated using electricity from nuclear energy. Just like green hydrogen, an electrolysis process is used. The difference is that the nuclear waste is created as a by-product of these processes. There are also some ideas to use the high-temperature reactors or available steam.

) hydrogen is made by a process called methane pyrolysis. The by-product is solid carbon. Depending on the thermal process that is used for pyrolysis — for example, whether it comes from renewable sources — and the capability to store the solid carbon permanently, this can be a low- or no-carbon process.

 hydrogen is produced by electrolysis directly from solar energy without the intermediate step of creating electricity. In some publications, the term ‘yellow’ hydrogen is used when the electricity for the electrolysis process comes from multiple sources, some of them renewable, some of them conventional.

 hydrogen, is naturally occurring geological hydrogen. Yes, there is a process that involves drilling a hole in the ground to get to hydrogen, with some fracking involved; however, there is currently no large-scale exploitation of this relatively rare resource.

Why do we care about these colors of hydrogen, especially since the machinery is agnostic to its source? There are two areas where the production source can make a difference: the pressure at which the hydrogen is available and the composition of the hydrogen gas.

Why are these features so important? Both relate to the fact that hydrogen compression is energy intensive. For a given mass flow, the amount of work to get a certain pressure ratio with pure hydrogen is almost 10 times higher than that of natural gas. Of course, hydrogen has a much higher energy density on a mass basis than natural gas (the lower heating value of hydrogen on a mass basis is 2.5 times that of natural gas), but even for the same energy flow, the compression work for hydrogen is four times higher.

On the other hand, even a small amount of composition impurity of the hydrogen, such as 4-5% carbon dioxide, can substantially lower the compression work by a factor of two. Therefore, it makes a big difference at what pressure and composition the hydrogen is made available in various compression processes. Also, both the combustion characteristics and the compression work change if other components (such as carbon dioxide or methane) are part of the hydrogen produced. Lastly, the capability of hydrogen to cause material issues (such as hydrogen embrittlement) can be influenced by the presence of other substances in the gas composition.

A third consideration of the source of hydrogen has less to do with the gas itself and more with the by-products of its generation process. Specifically, in processes that produce hydrogen from fossil fuels, carbon dioxide usually also is generated. For example, if blue hydrogen is produced from natural gas using steam reforming, about 10 kilograms of carbon dioxide are produced for every kilogram of hydrogen. In these cases, the separation, transport, and sequestration of carbon dioxide is necessary to maintain greenhouse gas neutrality — and that requires additional compression infrastructure.

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The Myth Busters discuss the many colors of hydrogen and their place in the energy economy.

The colors of hydrogen: Why do we care? 


As engineers, we usually operate under the mantra “if it ain’t broke, don’t fix it.” If an old piece of plant equipment operates effectively, we maintain it with tender loving care. Otherwise we don’t touch it. This approach has served us well in the turbomachinery industry, with many legacy machines worldwide functioning well after more than 50 years of service. Some “dinosaur” refinery compressors actually exceed 80 years and still work properly.

But there are reasons — economic, performance, and environmental — that drive us to replace these machines with newer models. They may break too often or cost too much to maintain. Spare parts may no longer be available. A degraded machine’s efficiency may be too low, or it may not otherwise meet design flow, pressure, or power requirements of a growing plant. It may be incapable of handling process changes like higher pressures or pressure ratios and the resulting rotordynamic challenges. Finally, environmental concerns and regulatory requirements may force the retirement of old equipment when it cannot meet acceptable emissions or other standards.

Industrial machinery like compressors, turbines, and expanders has come a long way over the last 100 years. Efficiency has improved, emissions have been reduced, and reliability/availability generally has increased. But there are cases where the newest equipment is not always better than what has been operating for a long time, particularly if operating conditions have remained the same.

Admittedly, older machines were sometimes engineered and manufactured “heavier” than modern machines. Older design tools were not as accurate as today’s advanced FEA and CFD methods. More conservative design margins were required. Increasing the energy density of the machine reduces capital cost per power installed. This has led to cost savings, smaller footprints, less weight, often better aerodynamics with better range and efficiencies, and more head per compressor casing — but not necessarily a more rugged machine.

Modern aerodynamic blades have been refined and optimized and typically are very efficient. They have complex 3D shapes and some-times operate on tighter margins of aerodynamic stability. We have learned a lot over the last 50 years about rotordynamics, blade dynamics, and bearing/seal design. Our design tools have gone through many generations of improvements and validation using test data. Although modern rotor and blade designs may not always look as rugged as previous generations, if properly designed, they are as reliable and have similar life expectancies.

Does it make more sense to uprate/overhaul/refurbish/repair an old machine or replace it with a newer model?

But there are exceptions: By cramming more head into a compression stage, sometimes newer machines may have lower efficiencies. Since they run faster with higher tip speeds, compressible effects can lead to larger aero losses.

The question thus becomes: Does it make more sense to uprate/overhaul/refurbish/repair an old machine or replace it with a newer model? The answer depends on many factors, including maintenance cost, service parts availability, performance and the machine’s ability to meet current safety, environmental or operational requirements. Another factor is whether the OEM still supports the machine and has the capability to bring the old machine to required new standards.

This discussion is too long to cover in a single article. But the following examples provide some insights into a few technical advances that did not necessarily result in more reliable machines:

Example 1: Most very old reciprocating compressors installed on U.S. pipelines are low-speed (up to 350 rpm) integral machines. These large, heavy machines manufactured prior to the 1960s have proven reliable and efficient. Nonetheless, for the past 25 years, pipeline operators have mostly installed high-speed, (up to 2000 rpm) separable compressors. They’re not nearly as reliable as old integral machines, and their efficiency is substantially lower because of higher flow, pulsation, and valve losses. But operators prefer the much lower initial cost (on a per-horsepower basis) over efficiency and availability and have been slowly replacing their integral machines with high-speed, separable reciprocating compressors.

Example 2: Dry gas seals were introduced about 40 years ago. After some infancy issues, they have proven reliable and effective in avoiding the introduction of oil into the process stream. Dry gas seals have completely replaced wet seals in the market, and for the last 15 years, few wet seals have been utilized in new compressors. However, in some dirty compression applications with significant particulate matter in the gas stream or other solid contamination, dry gas seals are sometimes less reliable than older wet seals, which are better at handling particulate matter. Yet it is nearly impossible to purchase compressors with wet seals anymore since very few OEMs offer them as an option

 Example 3: To meet ever stricter NOx air emissions requirements, gas turbine OEMs have developed dry low NOx (lean premixed) combustion systems. In parallel, to increase output power and efficiencies, firing temperatures have drastically increased over the last 30 years, requiring advanced super alloys and complex but very sensitive cooling schemes. Conventional low-temperature diffusion flame combustors used between 30 and 60 years ago are generally more forgiving. But they simply do not meet modern emissions standards and today’s expectations for total plant efficiencies.

Many turbomachines still operate well after 30 and sometimes 50 years of service. If a machine is well maintained, restaged, refurbished, over-hauled, and repaired as necessary, it can operate well beyond its original 25-year API target design life. There are even cases where older machines are more efficient and reliable than newer machines.

When considering the replacement of older machines with newer models, take care to evaluate the impact that doing so may have on all aspects of operation, performance, and emissions of a plant. Legacy equipment that has been in operation for decades may not necessarily be inferior to modern equipment when all factors are considered. It is often possible to update, upgrade, and overhaul equipment for much less money than it costs to buy new. When considering replacing an old machine versus refurbishing or overhauling it, take into account not just efficiency but also reliability, operability, range and maintenance costs.

The phrase "if it ain't broke, don't fix it" has served us well in the turbomachinery industry. 

Myth: New turbomachinery is always better than older machines 

Due to the global COVID-19 pandemic, we’ve been bombarded with information about personal air filters (facemasks), how to apply (wear) them, multistage filtration (doubling masks) and filter ratings (N95). As professional turbomachinery engineers, we’re rather amazed at some of the myths perpetuated about air filtration. But as much as we’d like to poke fun at urban legends, we’ll stay focused on air filtration for gas turbines.

The difference between a facemask and a gas turbine filter looks staggering: While a person inhales about two cubic meters of air in an hour, a typical mid-sized gas turbine will ingest over 200,000 cubic meters in the same period. But there are some critical similarities. What are they?

Well…air-particles are air-particles, leaks are leaks, plugging is plugging, and there are liquids the filter must deal with.

Fouling and degradation in gas turbines are to a large degree driven by the quality of ingested air and the fuel supply. The effect of contaminants from the ambient air on a gas turbine (or a human being), which can be controlled by a properly designed/operated/applied air filtration system, is determined by the contaminant’s particulate constituent, size, and wetness. Solid particles in the air can consist of or contain a number of substances — salts, biological matter (pollen, insects, bacteria, etc.), or various types of dirt and sand — that can create significant problems for engine health if ingested without a filter. Salt in combination with sulfur, for example, can cause accelerated hot corrosion.

Most industrial filters effectively remove air particles above a couple of microns in size. However, even the best filters can’t protect the gas turbine if air can bypass these filters. Open man doors or leaking seams in the filter housing, incorrectly installed filters, or leaking gaskets let unfiltered air enter the engine, which obliterates the benefits of an otherwise efficient air filtration system.

An air filter’s efficiency can be evaluated by mass, volume, or particle size filtration effectiveness. A metric that determines filter efficiency by particle size is the most meaningful. Thus, most air filters are rated by their ability to keep particles of different sizes from entering the engine. Since modern filtration systems have no problem keeping larger particles (5-10 microns or larger) from penetrating the gas turbine compressor, particle erosion is normally not a problem. It’s usually smaller particles that cause compressor fouling and potentially transport contaminants that can cause degradation and hot corrosion in the hot section of the engine.

One of the characteristics of a filter is the “most penetrating particle size,” the particle size for which the filter has the least efficiency. An N95 filter, for example, can remove at least 95% of particles in the size range of its most penetrating particle size, which is about 0.1 to 0.3 microns. For larger particles, the filtration efficiency is much higher — 99.5% for particles above 0.75 microns. Of course, an N95 respirator only achieves these values with a good face seal.

It’s also important to know that filtration efficiency of a given system is reduced for higher flow velocities through the filter. Efficiency often increases if the filter already has some collected particles and is nearing saturation.

Then there are liquids and liquid droplets. Unfortunately, the ability of a filter to keep liquids out is not directly related to its particle removal efficiency. Liquids, such as water, often can seep through most filter materials. In the process, they can dissolve solid minerals previously captured by the filter and pass them through. Liquid droplet penetration can be prevented either by separating the liquid droplets from the airstream using demister vanes or by stopping them from entering the filter material by making its surface hydro[1]phobic. The latter method can be used for filters that have a high efficiency for small particles. The former method requires high flow velocities, which compromises its ability to work effectively with filters that have a high efficiency for solid particles.

Why are we talking about this? Air filters can be very effective in protecting a gas turbine from particle penetration. But small particle effectiveness is limited. They always let a small percentage through. The difference between a highly efficient and a not-so-efficient filter can lead to reduced fouling and degradation rates (as expressed by the time between required engine compressor cleaning) by orders of magnitude. But the positive impact is wiped out if there are leaks in the inlet system — just like your N95 facemask is mostly useless if you’re not wearing it over your nose and mouth.

During the pandemic we've been seeing the perpetuation of myths surrounding personal air filtration (AKA facemasks). As much as we'd enjoy poking fun at urban legends, we'll stay focused on air filtration for gas turbines. 

Myth Busters: Dispelling air filtration myths in the age of Covid-19

For the last 15-20 years, additive manufacturing (AM) or 3D printing has been widely hailed as the best thing since sliced bread. This optimism has turned to irrational exuberance in the turbomachinery industry, where AM is supposed to solve complex geometry fabrication problems, lower manufacturing costs, and reduce lead times of critical components. Unfortunately, to date many of the promises of AM have yet to be realized. There appears no clear path forward to address some of the apparent limitations of this manufacturing technology.

Additive manufacturing (AM) is basically a niche manufacturing technology between casting and subtractive manufacturing. So far, the potential of AM for compressor manufacturing has been much more promise than actual reality.


Industrial centrifugal compressors use fairly standardized casing, sealing, and rotor support elements, but their internal flow path can be performance optimized for a specific application. Thus, their impellers appear at first glance to be ideal candidates for AM technology, which favors one-off customized fabrication.
This is especially true for modern, complex-geometry 3D impellers. Significant aerodynamic design improvements due to advanced computational fluid dynamics (CFD) and finite element analysis (FEA) tools have changed the shape of impellers from traditional, simple 2D to highly flow-shape, curved 3D geometries. The move from 2D to 3D compressor impeller geometries happened in parallel with a slow industry transition from two-or three-piece construction to single-piece construction, using either welding or brazing to combine the compressor hub and shroud. Single-piece impellers can usually handle higher-stress loads than two-piece impellers and also reduce fabrication quality flaws.
For most modern impellers that have complex internal geometries and are not cast, fabrication techniques typically require five-axis machining for large impellers or electrical discharge machining (EDM) for smaller geometries. AM has shown promise for the manufacturing of smaller impellers, but most commercially available AM machines are limited in size and cannot handle impellers larger than about 20 inches in diameter. Closed impellers add complexity to AM methods as most metal additive processes do not build in free space. The bridging of the cover between impeller blades requires temporary internal supports to provide a base to build upon. These supports have to be removed during post-processing. This is difficult due to the limited access resulting from the small size and complex geometry of the impeller.
The most common, commercially available AM method for printing metal compressor impellers is laser metal sintering using a metal powder bed (also called selective laser melting, direct laser melting or laser powder bed fusion). A laser acts as a localized heat source to melt and fuse metal powder into a desired 3D shape, using sequentially layered metal powder. This technology has rapidly advanced over the last 10 years and can be utilized with many of the standard metals, such as steels and advanced nickel alloys typically used for compressor impellers
The industry focus on additive manufacturing has been largely focused on nickel-based and titanium alloys that cost more than $50 per pound and are utilized for specialty applications. Most components within turbomachinery are manufactured from carbon steel, low-alloy steel, or martensitic stainless steel. While it is possible to additively manufacture components from these alloys, it is typically more cost-effective to machine them from wrought material. Additive manufacturers have very limited experience with carbon steels and stainless steels, and powder is not readily available for these alloys.
The printing process of a typical small impeller will usually take several days, sometimes weeks, depending on the speed of the AM printer, the shape, and the desired printing quality. Internal support structures will usually have to be added to the impeller model to maintain shape integrity during the sintering process. The programming of AM printers is not an automated process and requires special operator skills and experience.

After completion of the printing process, there is usually significant post processing and testing required. Removal of internal support structures can be complex and labor-intensive, particularly due to the fact that printed components are often manufactured from titanium or nickel-based alloys. The removal of the internal supports often results in ridges and internal passage imperfections that require post-machining, EDM, acid bath, or abrasive slurry extrusion for removal. Surface finish is usually grainy and rough, and the quality depends on the speed of the printing process and metal powder grain size. External surfaces require machining and grinding to improve surface finish. This all adds to lead times and costs. Current estimates are that for a typical AM manufactured impeller, about 60% of the cost comes from post-processing and testing, rather than from the printing itself.
Due to the nature of the printing process there is an increased chance of surface cracks or internal voids with AM. Surface testing such as dye penetrant and internal crack/void detection using CT scans or x-rays is usually required. Also, on a typical compressor impeller, geometric tolerances are about 3-5 times higher than similar impellers fabricated using EDM or five-axis machining. These increased manufacturing tolerances increase proportionally with the size of the AM impeller.
The original promise of AM was that “anyone” can print a piece without any special training required as long as they have the appropriate metal printer. This led to the idea that one could print compressor impellers and other spare parts at distributed local repair shops, avoiding transport logistics, long shipping delays, and reducing the overall lead time. However, the reality is that for current AM machines, specialized operators are required; and the post processing steps such as support material removal and surface machining still require qualified machinist and a well-equipped machine shop.
Clearly, AM has the potential to solve many problems in the future including making it possible to provide aerodynamically and structurally optimized geometries for higher head and higher efficiency, or allow for faster and local “as-needed” manufacturing, reduce manufacturing times. New methods are beginning to address some of the shortfalls, and AM’s capabilities are likely to expand in the years ahead. But the current state-of-the-art still limits AM to small and specialty geometries in the compressor industry. AM is basically a niche manufacturing technology between casting and subtractive manufacturing. So far, the potential of AM for compressor manufacturing has been much more promise than reality. ■

Derrick Bauer contributed to this article.

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 Manager for Systems Analysis 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.
Any views or opinions presented in this article are solely those of the authors and do not necessarily represent those of Solar Turbines Incorporated, Elliott Group, or any of their affiliates.

AM is the best thing since sliced bread, they said. But has the potential of AM for compressor manufacturing been more promise than reality?

Myth: Additive Manufacturing is the Answer for Everything

 Close up hand of engineer using measuring manifold gauge for filling industrial factory air conditioners after cleaning and checking for maintenance outdoor air compressor unit.

The first question is: What data do we actually need besides the obvious such as pressures and temperatures at the compressor suction and discharge, and the flow? Things like the gas composition, the compressor speed, and ambient conditions are also required. Gas composition is often neglected because it requires extra effort to sample gas and send it to the lab or at least have a calibrated on-line gas chromatograph. It obviously must be the gas composition at the time of the test, not some mixture sampled weeks ago. Even in pipelines, gas compositions changes frequently.

Test data is subject to uncertainties. As well as accuracy of the end-device, this includes the entire measurement chain, instrument location, number of instruments, and process stability. There can be systematic or random uncertainties. In field performance tests, systematic uncertainties dominates; averaging a lot of data does not automatically help. Many tests have uncertainties exceeding several percentage points, especially for low pressure ratio compressors. In these cases, the test must be done with accurate and calibrated instrumentation.

Unsteady operating or process conditions are particularly problematic for the accuracy of test data. It is near impossible to correct for unsteady operating conditions from process changes or ambient conditions. Most test codes were written for factory testing and provide allowable limits for unsteadiness. But these are often not easily achievable in a field test. A good test plan will include steps to ensure steady operating conditions for the duration of the test.

"It is possible to obtain valuable and accurate test data in the field. But it requires planning, preparation, careful testing, and the understanding of fundamental principles."

If a test point is to be compared with a compressor map to determine if the measured efficiency meets manufacturer predictions, we need to know compressor head, speed, and flow. These measured values each have associated uncertainties. Compressor speed is usually measured accurately whereas flow and head can have significant uncertainties, depending on instrumentation, operation, and process conditions. Note that flow measurement impacts the comparison of the measured and the predicted efficiency – if the flow is measured incorrectly, the measured efficiency is compared to the wrong efficiency on the compressor map.

It is often a good idea to plan for redundant measurement. For example, one can determine a compressor’s absorbed power from both thermodynamic measurements on the compressor and from data gathered from the driver. For a gas turbine driver, the engine fuel consumption, data from the engine factory test, or (if installed) from a shaft torque meter measurement, allow for direct comparison of driver and driven power to check if the measured compressor performance is reasonable. For electric motor drivers, the required power can usually be obtained from current measurements at the motor terminals. However, gearbox losses and motor efficiencies must be considered.

There are two reasons to test a compressor: to verify performance or to use measurements to verify the power from the driver. For the latter, we don’t need to test compressor efficiency. We only need compressor absorbed power. This also means that it’s not important where on the map we operate as long as the compressor absorbs the driver’s full load. Accuracy of power measurement depends on many variables.

Just to be clear and for all who are now worried about their test results based on this article’s title: It is possible to obtain valuable and accurate test data in the field. But it requires planning, preparation, careful testing, and the understanding of fundamental principles. ■

Many of us have to verify compressor and driver performance in the field. We do a test, read the data, and convert it to flow, head, and some other parameters. Voila, we have done a valid test and we believe our data. Not so fast!

My test is accurate

 IGV blades at the inlet of a compressor pre-swirl gas flow entering the impeller, reducing the amount of work needed from the main driver.[/caption]

Over the last few years, compressor manufacturers have invested significant research funding in an attempt to decrease bearing and lube oil temperatures in their machinery bearings by a few degrees. Sometimes hundreds of thousands of dollars have been spent to lower temperatures by just single digit numbers. These expenditures are driven by the need to meet recent generic industry standards for rotating machinery bearings that are being strictly enforced by several operators. Let’s review the origin of these standards and discuss when and where the strict application of these standards makes sense and when they are over-simplistic or overly conservative.

The function of bearings in a turbomachine is to support and center the rotating shaft against static and dynamic radial and axial forces. In most industrial compressors, steam turbines, and gas turbines, these bearings are of the tilting-pad fluid film type, using either a mineral or synthetic oil to cool and lubricate the bearings. There are clearly some fundamental physical limits on the lowest possible lube oil temperature in a bearing that is achievable based on the energy that is transferred from the rotating shaft to the stationary fluid film and the heat load that the oil can absorb, transfer, and transport for a given oil heat capacity and flow rate. Beyond these basic physical limitations, there are many design choices such as type of bearing, pad size, aspect ratios, thrust equalizing, oil injection points, angle of load variation, and a host of other complex geometric and operational parameters that affect the lube oil temperature.

American Petroleum Institute (API) standards had traditionally required bearing temperatures below 200°F for slow-running machinery such as pumps and motors. Until 2014, API standard 617, 7th edition for centrifugal compressors, allowed bearing and lube oil temperatures up to 212°F. But the 8th edition lowered this requirement to 200°F to be in line with other API machinery standards. Most machinery built and operated prior to 2014 seemed to operate just fine at the slightly higher lube oil temperatures. However, this change resulted in a rush by most machinery manufacturers to find methods to lower their bearing metal temperatures regardless of the actual benefit it provides to the bearing load carrying capability, or to the machinery unbalance response and stability.

Rather than blindly following specifications, one should always ask what the true limitations of a physical process are to make sure a specification makes sense for a given application. In this case, the limiting factors and critical parameters are: (i) the bearing pad hot spot metal temperatures, (ii) the temperature at which the lube oil starts degrading rapidly, and (iii) the temperature at which the viscosity of the lube oil is too low to provide a consistent pressure gradient film on the pad to support the required shaft loads.

With respect to hot spot metal temperatures, the material that is of concern is tin-based babbitt surface material. In principle, the failure mode is a function of the temperature, shear rate and hydrodynamic pressures, which are heavily application dependent. Tin-based babbitts can operate at temperatures exceeding 300°F. But since material strength degrades rapidly with temperature, practical limits are about 265°F for a tilting pad bearing as specified by most bearing and turbomachinery OEMs and 240°F as specified by most gear OEMs and AGMA specifications.

"The machinery operator should always evaluate previous manufacturer experience, specific design/application considerations, and operating/test data prior to insisting on a fixed temperature limit from a generic industry specification."

And yet, the temperature targeted by the most recent API standard is specified as 200°F inclusive of all hydrodynamic bearings, both fixed geometry and tilting pad; and over a wide range of applications, from slow moving motors and bull gears to high speed pinions, compressors, and turbines. In order to meet this requirement, other margins may be impacted whether it be critical speed separation margin or stability such as by reducing the journal diameter to decrease surface speed or by using a longer bearing thereby increasing the rotor bearing span. While still meeting standards, additional margins might be reduced in areas where they might be more preferred.

For lube oil degradation, a 230°F metal temperature is discussed by the American Society of Testing and Materials (ASTM D4304-17) as a criterion to switch from standard Type 1 and Type 2 mineral oils to a more high performing ASTM Type 3 oil, which is generally formulated for heavy duty gas turbine or combined cycle applications.

The other commonly mentioned requirement, albeit not apparently anchored in any industry standard, is that the bulk temperature, either from a common drain or reservoir, should stay below 180°F. This requirement is mainly based on operational experience and the basic rule of thumb that the oxidation rate of turbine oils generally doubles for every 18°F above 140°F bulk temperature. Finally, while lube oil viscosity is non-linear (mostly logarithmic) across machinery operating temperatures, a temperature increase from 200 to 212°F will not lower the viscosity below what is required to provide adequate viscosity for pressure film stability in tilting pad and fixed geometry bearings.

The other question that has an implication on the validity and value of the lube oil temperature criteria is the actual measurement location and associated sensor accuracy to measure the true metal and lube oil temperatures. In most turbomachines, film temperature of the bearing lube oil film is measured with RTDs or thermocouples below the babbitt surface at the assumed hot spot. This measurement is an indirect indication of the bearing surface temperature since the temperature sensors are recessed from the pad surface, and the hot spot angular position is variable especially for fixed geometry bearings typically used in motors. Furthermore, the hot spot is along the axial center of the bearing, but measurements are allowed to be taken off the center line if the bearing is long.

So, measuring temperature in fixed geometry bearings or offsetting the temperature transducer from the center line in long bearings will generally mean that the measurement is not at the hot spot and place a bearing at risk for failure at a low temperature, the kind of events that lead to lowering of temperature standards. On the other hand, when properly implemented, this measurement is an excellent and fast indicator to determine if the bearing is operating at excessive temperatures with possible hot spots. Thus, bearing pad metal temperatures should still be used for alarm and shutdown controls of the machine.

The bulk lube oil temperature is usually measured in the bearing (individual and common) drain, and the reservoir. These measurements provide a good indication of bulk temperatures and can be useful as an indicator whether the lube oil degradation temperature has been exceeded. But they are not useful to determine the actual temperature condition inside the bearing or, because of the measurement delay, as an alarm or shutdown.

While the 200°F bearing and lube oil temperature limit has become the accepted reality in the turbomachinery industry, it does not always make sense. It is not achievable for some applications. Simply enforcing this limit for all machines is an over-simplification that leads to expensive design conservatism and not necessarily a better bearing or better machine. The machinery operator should always evaluate previous manufacturer experience, specific design/application considerations, and operating/test data prior to insisting on a fixed temperature limit from a generic industry specification. (Brian Pettinato provided technical input for this article.) ■