Historically, the three most frequently reported points for leakage have been: seals; locally damaged or buckled thin shells such as thin-wall casings/piping, large shells, and thin-wall sections; and bolt connections such as flange connections and bolted sections. Many turbomachinery casings, bodies, compo nents, impellers, blades, and rotating parts are thin-wall shells or folded thin plates. Examples are casings, tubular/ cylindrical shell bodies, piping spools, and more. The shells are more complicated than flat plates because their bending cannot, in general, be separated from their stretching. Due to the curvature of the surface, a shell acquires a spatial stiffness that theoretically gives to it a larger load-carrying capacity. Therefore, thin shells have been widely used in many applications. But they are vulnerable to local buckling and damage. Failures in thin-wall shell-like parts and casings have been frequently reported.

Many turbomachinery casings, bodies, components, impellers, blades, and rotating parts are thin-wall shells or folded thin plates. Examples are casings, tubular/cylindrical shell bodies, piping spools, and more. The shells are more complicated than flat plates because their bending cannot, in general, be separated from their stretching. Due to the curvature of the surface, a shell acquires a spatial stiffness that theoretically gives to it a larger load-carrying capacity. Therefore, thin shells have been widely used in many applications. But they are vulnerable to local buckling and damage. Failures in thin-wall shell-like parts and casings have been frequently reported.

The reason that many shells fail at a much smaller load than the classical critical load is due to the combined effect of imperfections, defects, and nonlinearities. In practice, there are random imperfections and defects which affect shells and shell-like bodies. Even in careful experiments, the measured failure loads and collapse modes exhibit tremendous scatter due to random imperfections and defects.

Nonlinearities and imperfections/defects sensitivities manifest in a variety of buckling shapes and different forms of failures. Buckling may show rapid transitions from one shape to another. The buckling of a shell can lead to the leakage, fracture, or even total collapse.

Failures in thin-wall shell-like parts and casings have been frequently reported.

Too often, high imperfection sensitivity and high nonlinearity of mechanical behaviour of shells are the consequence of interactions. There might be many different buckling modes associated with the same or nearly the same buckling load.

Shells are sensitive to transverse forces, especially if they are simultaneously subjected to an axial compressive load. The weakening effect of component imperfections and defects is most pronounced in the range of intermediate slenderness. In those slenderness ratios, critical buckling stress and yield stress are roughly equal. The decrease in strength is most marked for shells and plates of intermediate slenderness subjected to compressive stressing. Unfortunately, these ranges are used in many applications. A pragmatic solution is: 

Verification for shell-like bodies and parts that considers all possible buckling/failures with all realistic details/imperfections/defects.

Alternatively, use sufficient safety factors to cover all buckling/failures to prevent leakage and breakage.


It is desirable to make allowances for abuse which may result from unexpected conditions, operator errors, or the effects of wear and tear on key components, subsystems, members, and connections. Care should be taken for vulnerable points such as thin shells. Stress conditions, manufacturing details, and cracking at or near high stress points in shells are important.

The flexibility offered by bolt connections in the fabrication, installation, operation and maintenance is another factor to consider. Any bolt connection is an expensive joint compared to welding. For bolting connections, many different risks should be mitigated and many requirements should be met. There are always risks of leakage.

Connections (whether welding connections or bolting connections) are important for turbomachines and associated piping. The type and details of connections between major assemblies, subassemblies, and piping spools should be studied with care.

Particular attention is needed for shell-like equipment and thin-wall bodies (large-diameter thin-wall casing, and piping) as they can easily be affected by local yielding and local buckling and subsequently failures. 

Amin Almasi is a Chartered Professional Engineer in Australia and U.K. (M.Sc. and B.Sc. in mechanical engineering). He is a senior consultant specializing in rotating equipment, condition monitoring and reliability.

Articles

Leakage sources include seals, thin shells, and bolt connections

Avoiding Leakage & Breakage

A centrifugal compressor rotor is a long beam with impellers on bearings, usually hydrodynamic. Such a system can vibrate when excited at certain frequencies. Mass distribution and shaft stiffness, together with bearing stiffness, define the natural frequencies of the shaft. Vibrational deflections for a given shaft are influenced by bearing stiffness (and support stiffness).


To vibrate, the system must be excited by a fluctuating force. That force can come from rotor unbalance, in which case the frequency of the excitation is dictated by the running speed. It can also come from the bearings or seals in the machine, so-called cross-coupling forces, or from aerodynamic excitation. Some forces depend on the density of the gas compressed, and design tools like swirl brakes can reduce excitation from seals.


A system that can vibrate but has no damping exhibits very large amplitudes when excited at one of its natural frequencies. These large vibration amplitudes cause compressor damage. In modern machines, we measure these amplitudes and shut the machine down if they exceed a threshold. In other words, any compressor rotor is subject to exciting forces, and damping keeps vibrations from becoming excessive. This explains why damping is necessary.


In general, damping comes from bearings — and in some instances, seals. But what does it mean? If we have a shaft vibration as a result of some excitation, and we turn that excitation off, the vibration of the shaft quickly decays if damped. Damping reduces the amplitude of a free vibration. The rate at which the amplitude of a free damped vibration decreases is known as the logarithmic decrement, or logdec, defined as the natural logarithm of the ratio of two successive amplitudes. The larger the logdec, the more damping in our rotor system. Logarithmic damping can be predicted with accuracy, depending on the experience of the designer working with similar geometries.


The key question during compressor design is, “Do we have enough damping?” The answer is contingent on the amount of destabilizing forces on the shaft, summarized as cross coupling. Cross coupling also can be predicted with some accuracy, but it depends on the bearings, compressor seals, and aerodynamic forces from the impeller.


There is general agreement in the industry that logdec is a good stability indicator for rotordynamics. There is even some consensus as to the appropriate limits of stability values. But, as with any complex mechanical simulation, there are multiple methods of calculating these values. Past studies show that different analysts, given the same compressor geometry, arrive at widely varying values for logdec. Thus, a fixed value for an acceptable logdec is meaningless because the answer relies on the way the analysis is performed. Different organizations and consultants use different codes, apply different boundary conditions, and build different models. In addition, testing is difficult on real compressor geometry.


A fixed value for an acceptable logdec ismeaningless because the answer relies on the way the analysis is performed.


With no consensus benchmark or gold standard, and no shared industry database of accepted test results, the experience of the analyst and the availability of test data is crucial. The correct prediction of logdec value can determine the success or failure of a design. Incorrect predictions can lead to design modifications, additional time on the test stand, and expensive project delays.


Once the compressor is built, damping can be measured — indirectly by verifying that the rotor system is stable at the prescribed operating conditions, or directly by using methods such as electromagnetic exciters or Operational Modal Analysis (OMA). Ultimately, an insufficient logdec can be detected by stability issues, such as subsynchronous vibrations.


Given the many influence factors that determine logdec, it can change over the life of the compressor. Any lateral analysis addresses these changes to some extent by considering maximum and minimum bearing clearances or different lube oil temperatures. More important, however, is the fact that destabilizing forces change with the operating conditions of the compressor. Higher pressures, restages and changes to seals and bearings can alter the destabilizing forces.


Even more important, there is no fixed number for logdec that guarantees the absence of stability issues. In other words, if your analysis method shows a logdec greater than 0.1, you’re not automatically fine — and if it’s lower, you’re not always in trouble. Rather, experience based on designing and testing compressors and the use of well-established analysis methods are the keys to success. ■

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.


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.

MYTH: LOGDEC….WHO STOLE MY DAMPING?

PowerGen 2022 featured a fascinating presentation by John Gülen of Bechtel Infrastructure & Power on the feasibility of hydrogen turbines. John is not what you would call a fan of the concept of powering very large gas turbines with hydrogen. He explained that it would be cost-prohibitive to run them on 100% hydrogen.


Gülen laid out what it would take to make the concept work at a more reasonable level of hydrogen consumption. He suggested that research and development was needed into an efficient turbine in the 200 MW range as the best chance of making hydrogen combustion a success (As shown in the figure, there is a big gap between those mid-size units and large heavy duty gas turbines). The proposed machine is detailed in a paper he gave along with Justin Zachary of Expertech Engineering at the proceedings of ASME Turbo Expo 2022 (GT2022-81807) entitled, “Feasibility of achieving 62% combined cycle efficiency with a 200 MW gas turbine”.


“The smaller the gas turbine, the better the chance of fully green electric power generation,” said Gülen. “We need smaller turbines to be able to burn meaningful amounts of hydrogen efficiently.”


He ruled out aeroderivatives due to their having a high pressure ratio, and too low an amount of waste heat to make them viable in combined cycle operation. He also ruled out large heavy frame machines, which have been receiving the lion’s share of investment by the major gas turbine OEMs over the last couple of decades. This trend appears to be continuing with hydrogen.


Gülen pointed out that they are not the best candidates if hydrogen-based combustion is to achieve efficient operation. The typical 50-Hz J+ Class gas turbine of around 575 MWe, for example, would burn nearly 40 tons per hour (t/h) of H2 based on the use of polymer electrolyte membrane (PEM) technology in an electrolyzer consuming 55 kWh per kg of hydrogen. Such an electrolyzer would require about 2.2 GW of green power. To put this into perspective, consider that the amount of total curtailed wind energy in Germany hovers around 6 to 7,000 GWh, i.e., enough to sustain that one gas turbine for about 3,000 hours at full load.


In the 60-Hz range, the average J+ class turbines of about 420 MWe would burn nearly 30 t/h of hydrogen. This would require the supply of about 1.6 GW of green power. When you consider the amount of wind and solar energy needed to produce the hydrogen feedstock to operate these large machines, raw economics and energy efficiency factors render them infeasible options. Again, to put things into perspective, total wind curtailment in the U.S. in 2020 was 13,000 GWh, which is roughly enough to run only two of those units at full load for 4,000 hours.


According to Gülen, a better approach if hydrogen-based gas turbine combustion is to ever gain traction would be to focus on a smaller model. A 200 MW gas turbine might burn only about 16 t/h of hydrogen or about 900 MW of green power. However, this requires investment. Such a machine would need to incorporate some of the features developed for J-class gas turbines that led to the achievement of combined cycle efficiencies exceeding 62% such as larger air flow and increasing the firing temperature.


His paper lays out the work required in a variety of areas such as the intake, compressor, combustor, turbine, and exhaust in order to create the ideal hydrogen-burning machine.


“Getting to 62% efficiency would make a big difference to the viability of a 200 MW turbine that could deliver meaningful hydrogen-fueled generation,” said Gülen.


Most 200 MW-range turbines are E-class, though a few are F-class. An upgraded F-class would be required for hydrogen generation to bring combined cycle efficiently beyond the 60% mark. A couple of existing models have some of the right characteristics, for example, the 100 MW model from Mitsubishi Power (H100).


Gülen’s ideal configuration for combined cycle hydrogen generation would be two-shaft with the compressor and three-stage high pressure (HP) turbine forming a self-balanced shaft. The low pressure (LP) turbine would have two stages. Using reasonable design assumptions, the combined cycle performance would be about 303.1 MW and 61.34% net LHV.


From a thermal cycle perspective, such a product is conceivable with a high-cycle pressure ratio and a J-class turbine inlet temperature. A two-shaft configuration is needed to achieve a mechanically feasible design. But high investment would beneeded in areas such as compressor and combustor design. OEMs are unlikely to make such an investment unless they can clearly see demand from the market. In Gülen’s opinion, such a product may only be viable in high fuel cost markets.


His conclusion, therefore, is that if hydrogen combustion has any future at all in combined cycle mode to produce consistent large quantities of power, a 200 MW gas turbine concept is a better approach. However, he doubts the likelihood of sufficient investment.


Note that, from an overall CO2 emissions reduction perspective, the end result is pretty much the same no matter how one goes about it. This is a direct function of available excess renewable energy to be devoted to green hydrogen production. However, using the manufactured hydrogen in smaller green generators that would be run to support renewable resources is a better strategy than burning it in one gigantic power plant that would be better suited to running at higher capacity factors.


“The best use of hydrogen in power generation would be to provide peaking or standby power with fully hydrogen-fueled small gas turbines,” said Gülen. ■

HOW FEASIBLE IS IT TO OPERATE GAS TURBINES ON HYDROGEN?

HYDROGEN TURBINES

Winter Storm Uri crippled infrastructure across the United States in February 2021. Texas was particularly hard hit: reports estimate that 69% of residents lost power and financial losses totaled $130 billion. No single generation type can take responsibility for the catastrophic blackouts. Instead, the least resilient facilities across all types of generation led to 60% less available capacity in the ERCOT market.


However, a new plant in Houston, Texas—a result of designing specifically for resilience—proved reliable in the historic storm. HO Clarke Generating Station (Figure 1) was created to meet the demands of typical Gulf Coast heat and increasingly common cold snaps. Owned by independent power producer (IPP) WattBridge, the plant leveraged a standardized design that enabled the 6xLM6000 facility to be commissioned two months ahead of schedule and fortuitously, a week before the storm began. The facility remained available throughout the weather event.


Policymakers and industry experts agree that fast, flexible, and dispatchable power is necessary for grid firming. In the United States, most major utilities rely on gas peakers to augment their coal retirements and support their growing renewables portfolio.


Aeroderivative gas turbines—the prevailing peaking power technology—are valued for full power fast starts in less than 10 minutes; low turn-down for loads with low unit emissions compliance; rapid load following of up to 25 MW/min, per unit; and minimal maintenance penalties for frequent starts. They offer modular power output, flexibility, efficiency, and reliability.
A single 300-MW frame turbine drops in efficiency and produces higher emissions when operating at 50% turndown. A six unit 300 MW aero facility, in comparison, can operate three units at full load. In the event of a turbine failure, only 17% of the total output is lost.


But aero peakers face economic hurdles as they operate with a low capacity factor, impacting revenue projections. This can make project financing difficult. One way around this is to stick to a standardized plant design and have a ready supply of replacement turbines available. This approach can deliver competitive installed costs.


Combustion turbine-generator (CTG) packages must be designed for both cold and hot conditions: anti-icing systems drive resilience in cold weather operation and power augmentation maintains output in hot weather operation.


In cold weather, the goal is keeping the facility online; a plant in Texas, however, will not require the same strategy as one in Minnesota. Anti-icing systems—traditionally overlooked in warmer climates—ensure sustained cold weather operation. Turbine icing begins at 40°F (4.4°C) (Figure 2), which means that most facilities in the world may experience icing at some point.


Though located in the warm Gulf Coast, the HO Clarke site is equipped with a package air recirculation system (Figure 3). It draws heated air from the engine compartment and recirculates it to the inlet air module. The system leverages waste heat from the turbine compartment and uses existing package exhaust fans to eliminate icing with minimal parasitic output losses.


Several other anti-icing technologies can be used to address turbine icing. These include compressor discharge pressure (CDP) bleed air recirculation, exhaust gas recirculation, and glycol heater and coil system. Regardless of the type of technology, any system only needs to raise the inlet air temperature by 5 to 10°F to eliminate icing risk.


For balance of plant (BOP) winterization, designers must balance operational strategies and procedures with costs. HO Clarke used water line recirculation, temporary insulation jackets, and temporary electrically heated enclosures. BOP designs should also minimize single-point failures that can reduce power output to include sufficient water and backup fuel storage, facility winterization, redundancy, and civil seismic/wind rating. Besides these package and BOP considerations, a comprehensive operations strategy, coupled with remote monitoring and diagnostic capabilities, helps to ensure continuous availability.


In hot weather, the goal is to maximize power output or minimize lapses in power output.


Turbine output is directly related to relative humidity and inversely related to temperature: as temperature increases, power output decreases. At 100°F (38°C) and 30% relative humidity, the base performance of an LM6000 engine degrades from 50 MW to approximately 27 MW (Figure 4). By implementing power augmentation strategies, such as low-pressure water-spray power augmentation, inlet fogging, evaporative cooling, and inlet chilling and coils, power can be returned to nameplate capacity.


Developers should carefully select power augmentation technologies to optimize the power benefit against CAPEX and OPEX. Factors to consider: Water-spray technologies and inlet fogging both require a consistent flow of demineralized water; evaporative cooling requires a separate, higher conductivity water feed, and causes increased static pressure on the turbine inlet, which results in efficiency loss; inlet chilling and coil systems tend to be both complex and costly. Given the annual number of hot Texas days combined with an ample supply of demineralized water, HO Clarke opted for water-spray augmentation and inlet fogging as the best way to maintain nameplate output.


Firm gas supply and adequate pressure are essential to resilience. Peaking facilities built on under-pressured fuel lines typically depend on gas compressors, which add significant expense in addition to a being a common operational point of failure. Because gas supply and gas compression can impact the economic validity of a project, designers must seek strategic access to reliable gas lines as was done with HO Clarke.


Implementing dual-fuel operations can bolster facility resilience. Using diesel fuel backed by adequate storage can provide valuable operational flexibility in emergency situations. Independent System Operators (ISOs) like ERCOT and PJM now provide guidance on days of fuel storage required.

Implementing dual-fuel operations can bolster facility resilience.

Given the potentially long-duration runs in the Gulf Coast of Texas, a 375,000-gallon water tank was added at HO Clarke that supports facility operation for approximately 14 hours. Concrete pads were also added for any needed rental demineralization trailers to augment existing systems.


Additionally, there are electrical design considerations needed to address redundancy and failures. This can include selecting how many turbine-generator packages should feed a generator step-up transformer, a well-thought-out breaker and disconnect switch configuration, and the use of double-ended switchgear. Emergency systems must be configured for the intended response strategy—whether to safely shut down or to continue with normal operations. In addition, blackstart capability can provide a means to get back online independent of a utility backfeed, as well as enable owners to improve project economics by participating in that ancillary service.


As extreme weather events—such as heat waves, droughts, wildfires, polar vortexes, and floods—challenge grid stability, the world will likely need an “all-of-the-above” solution to grid resilience. These include transmission infrastructure expansions, demand response management, long-duration energy storage, and alternative fuels. No matter the solution, peaker plants with resilient designs will remain the backstop to grid stability. ■

DESIGNING AERODERIVATIVE PLANTS FOR RESILIENCE

POWER RESILIENCE

Turbomachinery International recently toured Mitsubishi Power’s Orlando Service Center. Established in 2001 and expanded in 2008, the facility serves as a repair, service, and manufacturing center. The tour began in the Tomoni Hub which monitors more than 100 gas turbines throughout the Americas.


The Tomoni Hub leverages remote monitoring, digital control systems, predictive analytics, and AI to optimize power plants. It is the hub that provides support beyond monitoring. Operations specialists provide technical and operational assistance to customers 24/7. The Tomoni Hub also acts as a channel to O&M support for on-site personnel by providing real time operational support for the monitored fleet.

Prasanth Thupili, Senior Vice President of Power Generation Services at Mitsubishi Power Americas, said that the Tomoni Hub used to almost exclusively monitor gas turbines. But it now offers total plant monitoring including steam turbines and generators.


“We can do remote tuning and troubleshooting using augmented reality (AR) technology,” he said.


The Tomoni Hub receives a constant stream of data and metrics from its fleet. If something unusual is observed, combustor dynamics can be monitored and perform tuning remotely.


On the repair side, multiple in-house processes are offered. These include STEM machining (an acid electrolytic drilling technique), electrical discharge machining (EDM), milling, welding, brazing, thermal coating spray, coating removal, heat treatment, and various kinds of non-destructive examination (NDE).


The extent of the facilities was a big surprise. The entire center comprises a manufacturing and repair facility totaling about 190,000 ft2. The Mitsubishi Power Orlando Service Center manufactures vanes, blades, and compressor blades totaling approximately 15,000 parts per year.


“We manufacture turbine Row 1 and 2 blades in Orlando as these are the hot-test parts,” said Thupili. “The other rows are manufactured in Japan.”
He oversees an operation that includes gas turbine, steam turbine, and generator parts, fields service, specialty repairs, and an exchange program. He noted that the steam turbine service and repair business has picked up recently. This is due in part to delayed outages due to the COVID-19 pandemic.
“We have seen a surge in the scope of our steam turbine services to include a lot more onsite inspections and more unplanned work that needs to be done on blades and other components,” said Thupili.


The business has also taken on the role of servicing electrolyzers, including 40 massive Mitsubishi Power hydrogen electrolyzers that are being installed in the ACES project in Utah. That will involve onsite inspections when the facility commences operation in 2024. He doesn’t anticipate the need for shop inspections of these machines until around 2030.


“Customers want us to do more auxiliary work beyond the normal scope of gas turbine, steam turbine, and generator repair,” said Thupili. “They prefer a single entity to do everything rather than dealing with multiple parties.”
He noted that flexibility has become just as important to customers as reliability. Some want to reduce the load on their units, sometimes as low as 35%.


With the labor market being so tight these days, the company is investing in more robotics and tools so that its workforce can become more productive. Examples include a robot that can remove ceramic coating from parts and small robotic tools to check the health of generators during field inspections. These inspections are done in between the rotor and the stator.


“With this tool, we no longer need to take out the rotor,” said Thupili. “Instead of ten people needed for an on-site inspection and repair, it only needs a couple.” ■


ORLANDO SERVICE CENTER PROVIDES BLADE/VANE MANUFACTURING AS WELL AS REPAIR AND REMOTE MONITORING SERVICES

MITSUBISHI POWER

The U.S. Environmental Protection Agency (EPA) and other regulatory bodies around the world are turning their attention to the policing of fugitive emissions from sources such as fuel leakage, unburned methane, and other greenhouse gases (GHG) sources besides those related directly to the combustion process. A big reason for the surge of interest in methane is that it is said to be anywhere from 20 to 90 times more potent than carbon dioxide as a GHG (depending on the time frame considered). Thus, it has been labelled as environmental danger number one.

The Inflation Reduction Act, for example, reduced the amount of allowable methane leakage to 1% and placed a fee of up to $1,500.00 per ton for excess methane. Canada, too, has passed methane emissions reduction rules for upstream oil and natural gas facilities. These encompass extraction, primary processing, transport, storage, leakage from compressors, and fracked gas wells.


Natural gas producers, transporters, plant operators, and the industry in general, therefore, can expect the pressure to ramp up on the monitoring, measurement, and capture of fugitive methane emissions. Previous efforts centered around the minimization of methane flaring. The latest rules, standards, and net zero commitments take things to a whole new level.


The vendor community is responding. Solutions are coming to market that measure the amount of methane that spills out from oil & gas sites, detect various sources of fugitive emissions, capture any leaked methane and reuse it in combustion and other processes, and provide better sealing technology for pipelines and compressors. It is becoming important, too, to be able to report how much methane comes into a facility and compare it to how much is burned and recaptured.


“Natural gas, which is primarily composed of methane, has been regarded as a pollutant as well as a commodity since 2016 based on standards targeting oil & gas operations,” said Brian Kromer, Managing Director and Principal, Step2Compliance. “Controls must now be able to accurately calculate GHG emissions as well as the conventional pollutants. Facilities must learn to track the amount of methane leakage and find ways to recapture it and put it to use.”


Some are even flying airborne infrared spectrometers over oil & gas production basins in attempt to quantify methane point sources. They measure wavelengths in light to estimate the amount of methane. Some say their estimates are questionable. But inflated or not, they will be used to condemn production facilities. The best response is to do everything possible to prevent leakage.


Here are some of the things the vendor community has evolved to address this issue:


EagleBurgmann has developed RoTechBooster technology to reduce methane emissions. If compressors are stopped frequently, dry gas seals may become contaminated. This can be avoided by depressurizing the compressor housing. However during this process, large amounts of methane can escape. To avoid this and maintain pressure in the compressor housing during downtime, a rotating seal gas booster can be used such as RoTechBooster. It is an electrically driven seal gas booster that keeps dry gas seals clean during standby conditions, and at any time insufficient seal gas flow occurs. Its rotating design allows the compressor to be placed in a pressurized hold for nearly unlimited time. No venting or flaring is required.


The company has also released the CobaDGS zero emission compressor seal. In higher pressure applications such as natural gas compressors, conventional tandem dry gas seals are typically used to minimize leakage of natural gas/methane. Due to their tandem design, they meet safety requirements, and reduce emissions by up to 90% compared with oil-lubricated compressor shaft seals. In addition, less friction occurs, and the service life is longer. Nevertheless, tandem dry gas seals still leak some methane into the atmosphere during operation. Another possibility to eliminate seal leakage is to use dry gas seals in double arrangement supplied with nitrogen (N2). However, this seal configuration is less safe and only approved for low pressures. Besides, if the N2 supply is interrupted, the double seals can get damaged.


“For the CobaDGS dry gas seal, EagleBurgmann adapted the coaxial design of its CobaSeal for use at higher pressures,” said Benjamin Hellmig of EagleBurgmann. “The Cobaseal is a separation seal is a coaxial design that is also supplied with N2 but is resilient to gas supply interruptions. It can remain pressurized with N2 during operation and shutdown without contamination.”


Matthias Grapow, Vice President Business Intelligence and Business Development, MAN Energy Solutions, believes that producing biogas from organic waste will grow rapidly in the coming years. The company’s HOFIM-based Factory LNG technology is used at organic waste collection sites where biomethane (aka renewable natural gas) can be liquefied from biogas. Biogas or biomethane can be used for combined heat and power (CHP) operations or turned into electricity. This approach can also be used for small-scale LNG to enable natural gas to be supplied to places not directly tied to a mainline natural gas pipeline.


“Through a fleet of cryogenic transport tanks, the produced LNG can be transported over long distances by truck or trains to enable the provision of energy to isolated regions,” said Grapow.


The hermetically sealed and electrically driven compression HOFIM consists of a single rotating element, two radial and one axial bearing, no couplings, no gearbox, no lube oil and no shaft seals to atmosphere. These zero emission compressors are suitable for use in midstream gas transport, gas storage, small-scale LNG, upstream subsea, and topside compression.


“Instead of flaring production-related gas losses, the gases can be reused within the process for power or heat generation, or can be converted into transportation fuel or LNG,” said Grapow.


Tom Harper, Vice President, Emissions Management and Commercial Development Leader, Climate Technology Solutions at Baker Hughes, believes that the global oil and gas industry can eliminate 40% of its methane emissions at no net cost. It has developed various tools to meet this challenge.


The company’s Lumen Terrain and Lumen Sky technologies, for example, use analytics to detect, localize, and quantify methane leaks. This information can be used to prioritize recommendations for abatement, as well as supporting the verification of emissions reductions.


Another abatement solution is flare.IQ. It enables higher-efficiency flare combustion and reduced methane slip emissions. The Egyptian Ministry of Petroleum and Mineral Resources is deploying it in the refining sector in Egypt.


“This will lower flaring emissions from oil and gas operations by digitalizing emissions management infrastructure and pulling information about flare systems, substantially reducing emissions by ensuring a higher-efficiency flare combustion rate,” said Harper.


Siemens Energy’s flagship methane offering is the Spontaneous Leak Detection Service (powered by ProFlex) for gases, liquids and multi-phase fluids transported through pipelines. It utilizes signal processing on edge computing devices, Internet of Things (IoT) software, and data processing algorithms to identify leaks in near real-time.


“Our technology can detect leaks as small as ½ inch to 2 inches within seconds and provide accurate localization to as little as +/- 20 feet, while minimizing false positives,” said Anand Sengupta, Vice-President, Head of Global Sales,
Siemens Energy Compression.

The company has also developed predictive analytics technologies and digital twins that are used in Predictive Emissions Monitoring Software (PEMS) across the Siemens Energy small gas turbines portfolio. It helps operators predict regulated emissions accurately.


“Although methane slip or unburned hydrocarbons (UHC) in the exhaust of gas turbines is orders of magnitude lower compared to other engines, we’ve received many queries from customers, and are planning to incorporate the prediction of UHC into PEMS for small gas turbines,” said Sengupta


ABB has released of HoverGuard, an addition to its ABB Ability Mobile Gas Leak Detection System. HoverGuard is an Unmanned Aerial Vehicle (UAV)-based system that detects, quantifies and maps leaks up to 300 ft from natural gas distribution and transmission pipelines, gathering lines, storage facilities, and other potential sources. It automatically generates digital reports that summarize results and can be shared in minutes after a survey.


The cloud-connected, multi-gas solution quantifies the three most important greenhouse gases (methane, carbon dioxide and water vapor) continuously while flying. Cavity-enhanced laser absorption spectroscopy detects methane with a sensitivity more than 1,000 times higher than conventional leak detection tools. It can detect leaks while flying at altitudes of 130 ft or higher, and at speeds greater than 55 mph.

Enclosed Vapor Combustors (EVCs) are available from several vendors. They are being used, for example, in some Canadian gas facilities to address leakage at compressor and meter stations. Burners convert methane into water vapor and CO2. Testing has shown this technology to be 99.6% efficient in converting methane.


Klaus Brun, Director, Research and Development, Elliott Group, said his company is using technologies from others to improve methane emissions along its product line.


“We can utilize leak-free dry-gas seals or seal vent gas capture and recovery when a client requests it,” said Brun. “Our new 140 TCH pipeline compressor has a single dry gas seal instead of two seals to reduce dry gas seal leakage by 50%.”


He noted, though, that the biggest reduction in GHG emissions from compressors can be achieved by improving compressor efficiency or by converting the driver from an engine/gas turbine to an electric motor drive. Another way to lower methane spillage is to avoid shutdowns for blowdowns. That entails improving reliability and availability and eliminating false alarms.


Solar Turbines, too, is doing a number of things to reduce methane emissions. The company uses a system that gathers the leakage from dry gas seals and recompresses it back either to fuel gas pressure or compressor suction pressure.


ExxonMobil has reduced U.S. unconventional methane emissions by approximately 40% as of year-end 2021 when compared to 2016 by conducting tens of thousands of leak surveys and eliminating all its high bleed pneumatic devices. The company has developed ground-based continuous sensors, as well as aerial, airplane and satellites technologies to help with methane reduction.


“By 2030, we’re planning a 20% to 30% reduction in corporate greenhouse gas intensity, a 70% to 80% reduction in corporate methane intensity, and a 60% to 70% reduction in corporate-wide flaring intensity,” said Matt Kolesar, Chief Environmental Scientist at ExxonMobil.


BP has targeted zero routine flaring emissions by 2025 in its U.S. onshore operations and globally by 2030. It is deploying a variety of detection and monitoring technologies and is phasing out remaining pneumatic controllers.


Teledyne Flir’s FLIR GF320 detects hydrocarbon and volatile organic compound (VOC) emissions from natural gas production and use. With this optical gas imaging camera, inspectors can check components and see potential gas leaks in real-time. The GF320 is lightweight, offers both a viewfinder and LCD monitor, and has direct access to controls. Embedded GPS data helps in identifying the precise location of faults and leaks.


Vortex Services of Canada offers the Vortex Emissions Target Solution. It packages a elements that address methane measurement such as a fuel measurement, fuel valves, a display panel, sensors (O2 and NOx) a catalyst monitor, and several venturi elements to improve the fuel/air mix.


Continental Controls Corp. (CCC) offers a range of fuel control, fuel measurement, and emissions monitoring tools to accurately measure GHGs. Its Catalyst Monitor continuously measures pressure across the catalyst as well as pre- and post-catalyst temperature and notifies the user if minimum or maximum temperatures are exceeded. When combined with the CCC Air Fuel Ratio Controls (AFRC), it can make corrections to set points to maintain low emissions levels and extend the useful life of catalysts. This arrangement can be used to provide evidence of engine compliance and fuel consumption over an extended period of time.


“CCC continuously measures the true rate of methane compliance,” said Kromer. “Its tools can help monitor methane related to the exhaust as well as fugitive emissions.”


Utilities, owners, operators, and plant personnel are grooved in to measuring emissions in the exhaust, but not methane.


“Methane is not easy to eliminate and doesn’t go away when you use a three-way catalyst,” said Rick Fisher, Vice President at Continental Controls Corp. “Every compressor station and any plant running a gas turbine or gas engine is going to suffer methane leakage. Even something as simple as a shutting off a valve in a compressor station often leads to some venting of methane.”


Traditional monitors and controls are not set up to accurately measure methane. But owners and operators can expect stricter methane reporting such as on the amount of fuel that comes into a facility, how much was combusted, and how much methane leakage has been collected for reuse. ■


HOW THE INDUSTRY IS DEALING WITH NEW METHANE REQUIREMENTS

METHANE CAPTURE

Texas A&M hosted the 51st Turbomachinery and Pump Symposia in Houston during September. Attendance returned to pre-pandemic levels. The show featured a lively exhibit and a large collection of sessions, discussion groups, and case studies.


Michael Welch, Industry Marketing Manager, Siemens Energy, kicked off an early session on how to integrate turbomachinery into CO2 capture plants aimed at smaller, open cycle gas turbine applications. He reviewed one carbon capture approach based on the traditional amine capture system and another using pressurized hot potassium carbonate (HPC) concept.

Traditional systems are largely solvent based on absorption towers. The drawbacks include the need for power and heat, as well as a lot of space. They currently capture about 90% of the carbon, although this could be pushed up above 95% through additional investment. Additionally, the solvent must be regularly topped up. Electrical and heat consumption are a significant proportion of plant output. The small scale makes amine tower system costs relatively high.


“Advances such as rotating packed beds (RPB) can be used to reduce energy and space requirements,” said Welch. “The size of the absorption system is reduced by 7 to 10 times.”


However, low flue gas temperatures are still required. There is currently a limit as to how large they can be scaled up. As a result, the price tag comes down for small CO2 capture plants, with forecasts that $50/tonne could be achievable.


HPC, meanwhile, scales well and generates its own power and steam. But this approach has a high space requirement (about the same as amine towers). On the plus side, HPC can accept high temperature flue gas from gas turbines without the need to reduce the flue gas temperature. This pressurized high temperature system can generate sufficient electricity for its own use, even producing surplus for export in some cases. It can be configured to recover waste heat, too, for various purposes.
But the big barrier to broad adoption of carbon capture is cost. Amine towers have CO2 capture costs that work out around $80 to $150 tonne for a small capture plant. RPB and HPC could achieve around $50 to $80 tonne in the right circumstances. Mixing hydrogen with natural gas can bring costs down further.


“If you add 30% hydrogen into the mix, you can achieve an 11% reduction in carbon emissions, so there is less CO2 to capture,” said Welch.
Another way to reduce costs is to consider boosting the CO2 concentration in the flue gas by using exhaust gas recirculation. This reduces the amount of solvent required in the process and hence the size of the reaction vessels
Waste heat recovery is an additional strategy being used to improve project economics. There are various ways to recover heat from the CO2 compression process and integrate it back into the amine system. Recovering and integrating CO2 heat of compression, for example, can reduce the parasitic burden of carbon capture and lower compressor cooling requirements. This approach could be used with either single-shaft or integrally geared compressors. The latter was found to offer more flexibility in optimizing compressor pressure ratio splits.


The carbon capture theme continued with a presentation by Klaus Brun, Director of R&D at Elliott Group and long-term Myth Buster for Turbomachinery International. He outlined the new for new approaches to compression of carbon dioxide for separation, pipeline, transportation, and storage injection. For every kg of blue hydrogen that is produced through steam reforming or partial oxidation gasification, for example, about 10 kg of CO2 is also produced. This CO2 needs to be compressed from near-atmospheric conditions for pipeline transportation and then to geological formation storage pressures for long-term sequestration.


One promising technology for large-scale carbon storage compression applications is a hybrid combination of a centrifugal compressor to compress the gas to slightly above its critical point in series with a dense phase pump to reach the desired process discharge pressure. This combination of turbomachinery can be packaged with a driver with a single gearbox for the compressor and direct drive for the pump.


“We have about 250 years of storage capacity for CO2 in the U.S. in old mines and geological formations,” said Brun. Putting it in the ground requires about 1800 psi compression per mile of depth. Pipelines are needed to transport the CO2 as well. That means the carbon dioxide needs to be cleaned and dried and a boost compressor is needed after capture to maintain pipeline pressure. CO2 transportation requires very high pressure ratio compressors with intercooling.


“Centrifugal compressors are preferred as recips have issues with pulsation control, lube oil contamination, leakage, and reliability,” said Brun.

Tim Allison, Director of the Machinery Department at Southwest Research Institute provided a rundown of the different mechanical approaches to long-term storage of energy. Batteries are good for short-term storage. But the longest duration approaches are machinery-based, such as compressed air energy storage (CAES) and pumped hydro systems (PHS).

“As we seek to decarbonize electricity, there is a variable demand mismatch coming from wind and solar resources,” said Allison. “Studies show that storage on the order of current daily energy production or more may be needed.”
He gave the example of metropolitan Phoenix. 10 hours of energy storage for the city would amount to 125 GWh. Five of the world’s largest PHS units would be needed to supply that amount of storage. To match the energy capacity of the U.S. natural gas storage system, 57,000 PHS systems would need to be installed.


Allison noted that the figures used to support the low cost of solar and wind tend not to take into account capacity factor and storage costs. Solar has a 25% capacity factor, and wind has about 35%.


“When you add in storage costs, capacity factor, and round-trip efficiency, gas turbines remain much cheaper,” said Allison. “Machinery based solutions offer long-duration storage at the lowest cost.

Medhat Zaghloul of Compressor Control Corporation delivered a session on compressor refrigeration in oil & gas. The pressure ratio requirement of refrigeration compression depends on seasonal ambient conditions, rather than on process cooling demand variations. Machines in the summer typically require more horsepower to drive them. Overdesign in controls is a common problem.


If a control element is placed between the economizer and high-power suction drum, there is a chance for upstream pressure to raise in a partially closed valve scenario. Having a control system in this configuration negates economizer benefits. Single mixed refrigeration (SMR) compressors in small LNG plants are straightforward. The setup involves a two-section SMR, with a variable speed gas turbine driver. The mixed vapor from the cryogenic heat exchanger (CHE) is compressed in the low-pressure section. It produces a mixed phase stream, with the liquid portion used for process cooling and the vapor portion further compressed in the high-pressure section, and then condensed for process cooling.


Jim Sorokes, an independent centrifugal compressor consultant, examined advances made during the last seventy years in design, analysis, and manufacturing methods.


Compressors were driven by cost and ability. Machining limitations pushed design philosophy. The industry relied on cast internals for manufacturing, and performance wasn’t as important. Rising energy costs forced consideration of performance. There became a desire to consume less fuel, have a smaller footprint, fewer stages, and a wider flow range.


One of the most significant changes was dimensional design considerations. 2D blade performance is what led to 3D blade production. Achievable in 3D is high Mach, matching inlet flow angles, better control of area distribution through the bladed passage, uniform exit velocity, and diffuser performance.
Additive manufacturing (AM) is a modern discovery. Creating parts with AM methods increases freedom in blade shape. Size limitations and surface finish treatments can alleviate issues from printing, such as webbing.


Mark Sandberg, independent consultant, covered compressor configuration, sizing, selection, and arrangement. Configurations were initially straight-through versions – a single collection of stages with a common inlet and discharge. Beam style rotor designs limit the number of stages to ten, although high flow coefficient stages can limit this further.


Compound configurations comprise two or more sections in a single casing. Since controlled leakage seals replace one stage in this design, stage number is limited to nine or less. Space for multiple inlet and discharge nozzles also caps possible sections. Other types are back-to-back, double suction, and sideload.
Important considerations for sizing and selection are flow rate, suction pressure, temperature, discharge pressure, gas composition or specific gravity, unique side stream flows or pressure requirements, and any rotational speed requirements. Common selection parameters are volumetric flow rate, polytropic head, polytropic efficiency, and gas power.


Compressor arrangement is the external structure and organization of compression hardware. Series arrangement considers that as head requirements increase, multiple casings are needed to achieve desired compression ratios. There is a separate driver for each casing. Tandem arrangement means one driver handles multiple casings. Required flow rate and driver type can influence selection between series and tandem arrangements. Casing selection must be optimized based on specific operating parameters. Compressors laid out in series arrangement are less reliable due to additional drivers.


Sandberg said, “Proper setup allows centrifugal compressors to run roughly seven years without maintenance.” ■

Refrigeration Compression, Turbine Performance, Compressor Advances, Carbon Capture, and Energy Storage