Axial compressors are used in processes where a large amount of gas is required, providing high efficiency relative to their size. Industrial applications include first-stage mixed refrigerant compressors in LNG plants, main blowers in refineries using the catalytic cracking process, and blowers for blast furnaces in steel mills.

There are two restrictions on the operation of dynamic compressors caused by different phenomena: at relatively low flow rates - surge; and at relatively high flow rates, a choke or a stone wall. These conditions must be taken into account in design so they can be prevented.

Due to the severity of surge and the much higher likelihood that compressors will operate at relatively low flow rates, this issue has received more attention. The surge phenomenon can be described as erratic operation accompanied by strong mechanical vibration, rotational speed fluctuations, pressure fluctuations, gas velocity fluctuations, and rapid temperature rise with possible overheating and abnormal sound generation. The choke phenomenon can be defined as increased vibration, temperature rise, and a rapid drop in efficiency. If the choke is not as strong as the surge, prolonged operation in the choke zone may damage the compressor.

Both surge and choke are fluid mechanics phenomena that occur in compressors under certain circumstances. Dynamically unstable compressor operation due to surge or rapid efficiency drops due to choke can occur at different speeds, inlet pressure, inlet temperature, and different molecular weight of gases (in LNG applications). Therefore, the theory of experimental fluid mechanics must be applied.

The principles of similarity and dimensional analysis are used to generate modified dimensionless compressor maps with fixed surge and choke limiting lines for all inlet conditions, gas compositions, and rotational speeds, which can then be used in various surge and choke protecting algorithms. The most commonly used dimensionless coordinates of such maps are compression ratio and corrected mass flow rate.

Close-loop PID controllers are typically used to regulate anti-surge valves to protect compressors from surge, and to regulate inlet guide vanes (IGV) or outlet valves to prevent compressor choking by comparing the controlled variable (CV) to the desired SP setpoint. There are various compressor protection algorithms that calculate the CV that characterizes the position of the operating point relative to the choke line, represented in dimension-less rectangular coordinates.

The most commonly used choke protection algorithm in industrial control systems, or its derivative, defines the CV (%) as the distance from the operating point to a point on the choke line at the same compression ratio. Other algorithms define the CV (%) as the distance from the operating point to the point on the choke line at the same mass flow. In rectangular coordinate systems, the distance between points on a curve and the curve itself are projections onto a horizontal or vertical axis.

The first algorithm requires extrapolating the choke line so that the vertical coordinate passes through it. Compressors are selected to operate at points with maximum efficiency, somewhere between the surge point and the operating point OP (Figure 1) in a curve where the accuracy of calculating the controlled variable to protect compressor from choke is minimal, since the position of the point (B)Rc is an assumption. The accuracy of the operating point calculation increases as the choke point is approached, but may still be inaccurate within the safety threshold.

Algorithms of the second type seem preferable, since the projection of the operating point on the horizontal axis always intersects the choke line. In such algorithms, the displacement of the operating point is determined by the vertical coordinate of the compression ratio as a function of the horizontal coordinate of the corrected mass flow rate, then a small change in distance between the intersection point (B) on the choke line and the choke point can significantly change the distance, which makes it difficult to tune the PID controller for its fast response.

Setting the safety threshold in rectangular coordinate systems can only be made relative to the choke line, since the entire operating range is not available. The compressor performance curves on the plane are geometrically limited to perpendicularly oriented lines to reproduce the entire operating range from the surge point to the choke point, which is achievable in a polar coordinate system defining this range as a rotation from the polar angle to the polar angle. Therefore, the controlled variable CV (%) for the choke protection controller can be calculated as the choke point polar angle minus the operating point polar angle divided by the entire range, which is equal to the choke point polar angle minus the surge point polar angle. 

Polar coordinates provide the most accurate representation of the operating point in relation to surge and choke limits, reproducing the full range of operating points at which the safety threshold control setpoint can be set exactly as required. And the controlled variable calculated in the polar coordinate, is an almost linear variable, which makes it easier to tune the PID controllers.

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Articles

Compressor choke

BY HASANUR JAMAL MOLLA, SAAD H. AL-DOSSARY, TARIQ NADEEM, AND MOHAMMAD F. AL-SHIHRI.

Varnish is an organic residue produced by irreversible chemical degradation of mineral oil lubricants. It can lead to filter plugging, restricted oil flow, poor heat transfer, valve sticking, fail-to-start conditions, and unit trips. 

During rotating equipment operation, heat generated due to friction degrades the oil and produces very small by-product particles that settle throughout the system as varnish. Spark discharges from static charge buildup in the lubricating oil filters play a key role in its formation. Over time, these particles attach themselves to surfaces throughout the turbine, producing a sticky film. As varnish builds up, performance of rotating equipment suffers. 

A variety of varnish removal systems are avail-able in the market. As the conversion between soluble and insoluble varnish is a physical equilibrium process dependent upon temperature, Varnish Removal Units (VRU) are equipped with a cooler to reduce the oil temperature and convert soluble into insoluble varnish. Special filter media inside the VRU capture dissolved and suspended soft contaminants from the oil.

Varnish is a sub-micron-sized soft contaminant that is polar in nature. Oxidation and thermal breakdown are among the causes of varnish formation. But the two major reasons are micro-dieseling and static electric discharge. 

In micro-dieseling, the implosion of entrained air bubbles as they migrate from low-pressure zones to high-pressure zones creates a local oil temperature in excess of 1,800ºF. This is enough to cause severe oxidation of oil molecules and generates carbonaceous byproducts. As system pressures increase, the potential for micro-dieseling rises.

The industry’s shift to synthetic and glass filter media has created unexpected side effects due to the combination of tighter filter pore sizes to remove fine sediment with very high filter flux rates to reduce capital cost. The result is significant static charge buildup within the oil system. These spontaneous discharges can generate sparks of static electricity with temperatures greater than 18,000ºF. This “cooks” the oil, creating molecule fragments that deplete antioxidant additives. The oil circuit where there is metal-on-metal contact can also generate a static charge.

The conversion between soluble and insoluble varnish is a physical equilibrium process dependent upon temperature.

Oil-degraded soft contaminants are dissolved in the oil at operation temperature which are polar in nature and get absorbed onto dipolar (colder) metallic surfaces. The varnish is formed by soft contaminants agglomerating and hardening into a lacquer-like coating on valve spools and sleeves, bearing surfaces, gears and other internal surfaces of the lubricant system. 

The sticky nature of varnish captures hard contaminants as they flow within the system, forming an abrasive finish that accelerates component wear. Furthermore, varnish is an efficient insulator that provokes bearing surfaces to run hotter, and heat exchangers to have lower efficiency.

In Saudi Aramco, all critical rotating machines are monitored by a lubricant condition monitoring (LCM) system. The scheduled samples are tested inhouse. Test slates are decided based on oil type and equipment. However, color and acid number are checked for all industrial lube oils. When color and acid number are high, the RULER (Remaining Useful Life Evaluation Routine)/ RPVOT (Rotating Pressure Vessel Oxidation Test), and UC (Ultracentrifuge)/ MPC (Membrane Patch Colorimetric Test) are checked to understand the condition of the oil and design the corrective action to prevent unscheduled equipment downtime.

The MPC test has been used for many years in oil analysis as a qualitative test to assess the condition of oil. Recently, several commercial laboratories have developed quantifiable scales to trend the varnish potential of oil. For example, on Analyst Inc.’s scale from 0 to 100, a varnish potential rating of 0 to 15 is considered normal. The range 15 to 30 means monitoring is required. Readings greater than 30 are considered action-able and should trigger rapid remediate.

Delaval make a 5-stage centrifugal low-pressure (LP) gas compressor driven by a 3,500 hp electric motor. It is a critical asset, operating throughout the year with no standby equipment. The compressor takes gas from the LP suction drum and discharges it to the high-pressure (HP) gas compressor. The compressor runs at 10,295 RPM and delivers 19.27 - 21.55 MMSCFD of gas, with the amount varying from summer to winter. The set alarm and trip temperature of the compressor bearings are 235oF and 250oF respectively.

The compressor train is lubricated through a forced feed system to provide lubrication to the motor, gearbox and compressor bearings. The lube oil reservoir capacity is more than 3,000 gallons of ISO VG 46 turbine oil. 

The bearing temperature trend of the LP compressor showed a gradual increase at the inboard (I/B) bearing. It reached above the limit of 250oF and resulted in a trip. The bearing was dismantled, and varnish was found on the bearing. This lowered the oil flow rate because of reduced clearance and a reduced heat dissipation rate (Figure 1 and 2).

An offline Varnish Removal Unit (VRU) was connected to the LP gas compressor lube oil system while the machine was running. The VRU suction is taken from the lube oil reservoir drain valve. The VRU discharge is returned back to reservoir through a one-inch socket welded on the reservoir inspection manway.

The VRU utilizes filter media optimized for varnish removal. The warm oil is drawn from the system tank to the VRU by means of the transfer pump. The oil first passes through a blast cooler, then a heat exchanger and finally a chiller system before reaching the filter housing. The oil temperature comes down to approximately 50°F before reaching the filter media that captures dissolved and suspended soft contaminants.

Varnish has traditionally been defined as an insoluble deposit. However, it also exists in soluble state. The conversion between soluble and insoluble varnish is a physical equilibrium process dependent upon temperature. The soluble varnish becomes insoluble by reducing the lube oil temperature and can then be removed easily from the lube oil system.

After extracting the varnish from the lube oil, it is returned to the main lube oil system. Varnish-free oil now starts to clean system components in contact with oil, resulting in a varnish-free system for up to a few months depending on system condition.

After utilizing the VRU for a few weeks on the LP gas compressor, bearing temperatures and the condition of the lube/seal oil were improved. Oil samples subjected to MPC tests showed a drop from 39.1 to 1.4 within 19 days of operation. Bearing temperatures dropped from 249.4oF to 186oF within 19 days due to the removal of varnish and better heat dissipation as well as increased oil flow.

The usage of the VRU in combination with MPC testing of the lube oil system reduced the bearing temperature by detecting and cleaning varnish deposits. This improved heat dissipation and prevented any equipment trips due to high bearing temperatures. It also eliminated the immediate need for oil replacement, system flushing, and chemical cleaning.

Varnish removal technology in turbine oil. 

Resolving varnish challenges

BY BENJAMIN HELLMIG AND GUILLAUME DE FOMBELLE

Methane accounts for the largest share of greenhouse gases after carbon dioxide. It is many times more potent but has a shorter lifespan in the atmosphere. Methane emissions are usually not entirely avoidable. Compressors in gas pipeline compressor stations leak due to their design as the mechanical dry gas seals currently used do not seal completely. 

Pipeline operator GRTgaz from Western Europe decided to tackle the problem. Its infrastructure consists of several thousand kilometers of pipeline network with around 10,000 delivery, regulating, or sectioning stations as well as numerous compressor stations. Dry gas seals have been installed at new compressor stations for 25 years, and pipeline venting emissions (mainly for maintenance needs) are fed back into the pipeline with mobile gas compressors. Based on 2016 figures, the company has achieved a two-thirds reduction in methane emissions. The next target is to divide that number by five by 2024.

Conventional dry gas seals reduce emissions by up to 90% compared with oil-lubricated mechanical seals. Their tandem design meets safety requirements. If the main or primary seal fails, a secondary seal withstands full pressure. Other advantages include lower friction, longer service life, and efficiency.

If compressors do not remain in continuous operation, this can lead to seal contamination. There are several strategies to avoid this: A common practice is to depressurize the compressor housing, which results in methane escaping into the atmosphere. A better way is to keep the compressor housing pressurized during downtime. GRTgaz has implemented this strategy at several compressor stations using a rotating seal gas booster. 

Another way to minimize leakage is to use dry gas seals in a double arrangement. They are supplied with nitrogen, which then enters between the seal surfaces as a sealing gas. This means that no impurities are created, and only small amounts of nitrogen enter the compressor. However, the reliability of the supply is crucial. Without nitrogen, double seals are damaged. In addition, their safety level is only sufficient for lower pressures. 

Coaxial dry gas seals designs are similar to double seals. They can prevent leakage, are supplied with nitrogen, and are used at low pressures. The main advantages over double seals: their small footprint (comparable to a single seal) and resilience to nitrogen failure arising from a problem with the nitrogen generator. 

This coaxial design has been adapted for use at higher pressures. This gives components more stability as well as additional secondary seal faces behind the coaxial seal to provide a safety level like that of tandem seals. If the nitrogen supply fails, the system can continue to operate with process gas. In such a case, only small amounts escape into the vent line. 

This seal eliminates leakage during operation and shutdown. As it is permanently pressurized with nitrogen (N2), venting is no longer necessary. This also prevents contamination. The system operates at up to 160 bar operating pressure, even in the event of an N2 failure. Modifications to the compressor housing are unnecessary. It is suitable for new compressors and retrofits. 

Although it can operate without nitrogen, an uninterrupted supply is important for environmental protection and to ensure clean gas. Instead of transporting it to the compressor station, the nitrogen had been successfully generated on site in the GRTgaz pilot project through pressure swing absorption. The nitrogen accumulator that secures the supply operates at 330 bar. Pressure is reduced downstream to the required seal supply level. It is estimated that this new seal design saves on average 230,000 cubic meters of process gas per year while reducing overall operating costs.

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Compressor seal addresses methane leakage. 

Methane emissions

Since its founding in 1965, Sullair offers a line of portable and industrial air compressors, including Class 0 certified oil-free compressed air solutions. From scroll to rotary screw to centrifugal, the Sullair oil-free portfolio is available in powers from 2 – 30,000 hp and pressures from 15 – 725 psi. Sullair became a Hitachi Group company in 2017. The combination of two compressor OEMs brings more solutions to achieve their compressed air needs.

70% of all industries use some form of compressed air. In any industry it is used, compressed air directly or indirectly encounters the product being manufactured. In the food and beverage industry, for example, this means the packaging or containers holding the food or beverage, or the food or beverage itself. In pharmaceuticals, this means pills or bottles holding the pills, and so on. When using oil-flooded air compressors—especially if they are not well-maintained—there is a risk of oil passing through the compression chamber, making it downstream, and contacting the product. This jeopardizes the health and safety of the consumer. Therefore, an increasing number of industries—including food and beverage, pharmaceutical, automotive, medical, electronics, and power —are moving to oil-free compressed air systems.

WHAT ADVANTAGES DO OIL-FREE CENTRIFUGAL COMPRESSORS PROVIDE?

Centrifugal compressors provide superior energy efficiency for large volumes of air as advanced technology impellers are designed to match the required airflow and pressure. This means additional energy savings. They also provide low maintenance costs, as they’re designed with many non-contacting internal components. This ensures minimal maintenance needs. Additionally, all moving parts are easily inspected by removing the horizontally split gear cover. Centrifugal compressors provide Class 0 oil-free air for applications where air purity is essential.

Oil-free air compressors are cost-effective when looking at total lifecycle costs. They require minimal maintenance. A properly configured oil-free system lowers energy consumption. Further, many multi-national manufacturers are moving to oil-free compressed air systems to protect themselves against potentially damaging effects—such as contaminating end product, damaging production equipment, causing downtime or damaging their brand’s reputation due to the low quality of the end product and/or product rejections.

WHAT ARE YOUR T-SERIES COMPRESSORS USED FOR?

With T-Series compressors, Sullair offers six off-the-shelf integrated packages, all providing Class 0 oil-free air. Key features include titanium impellers as standard to extend the life of the compressor. An accessible horizontally split gearbox allows for quick inspection. A thrust collar design extends bearing life and increases impeller rotation stability. Additionally, an Allen-Bradley programmable logic controller (PLC) is standard on all models. Sullair T-Series compressors are primarily used in automotive, steel, glass, food and beverage, air separation, large industrial manufacturing, aircraft manufacturing, plant air for chemical, and petroleum processing.

Sullair f-series compressors are designed to meet specific needs. They are custom engineered to meet high pressure and flow applications. They produce Class 0 oil-free air. There are also custom seal designs available for specialty gases. Our f-series compressors are primarily used for steel, air separation, glass, automotive, process gas for chemical, and petroleum processing.

IHI-Sullair Compression Technology is a joint venture between Ishikawajima-Harima Heavy Industries (IHI) and Sullair to design, produce, and sell advanced centrifugal compressors. We have been part of this joint venture since 2004. The line, branded Sullair powered by IHI, is supported by Sullair distributors throughout North, Central, and South America. The Sullair-IHI centrifugal line is complementary to the rest of our oil-free compressor offerings, engineered and manufactured by Sullair and Hitachi. These include the DSP Series oil-free rotary screw air compressors and SRL Series oil-free scroll air compressors. The DSP Series is supplies oil-free air reliably and efficiently. Features include an air end design optimized for efficiency, an oil mist remover that improves air quality while reducing top off requirements, and a motorized isolation valve that provides additional protection against downstream humidity (A big enemy of oil-free screw compressors).

WHAT TRENDS HAVE YOU NOTICED OVER THE PAST YEAR?

While there are currently few government regulations in place regarding the mandated use of oil-free air compressors, there is a growing push to change this in some industries. This is leading to an increase in multi-national corporations switching to an ISO 8573-1 certified class 0 oil-free compressed air system. Another trend is that as customers continue to emphasize sustainability, energy conservation lies at the forefront. The cost of energy can quickly surpass the upfront cost of an air compressor. Energy conservation favors larger centrifugal compressors.

Brian Tylisz, Senior Vice President of Sales, Americas at Sullair, discusses centrifugal 
compressor and air compressor technology.

Q&A: The need for oil-free compression

FS-Elliott is a manufacturer of oil-free air and gas compressors. In addition, it provides a line of lubricants and control systems. The company has been in business for over 50 years and operates in more than 90 countries. “Despite widespread cuts in spending from customers due to COVID-19, we are experiencing increased demand in some industries,” said Alex Curtin, Product Manager, Engineered and Air Separation at FS-Elliott. “The fact that the major oil indexes have steadily rebounded and major investments to address the global chip shortage are indicators of a strong air compressor market.” But the pandemic caused a shift in strategy for 2020. The company refocused its efforts on internal process and product management modifications to offer engineered products with improved prices and lead times. In addition, it revamped extended warranty programs, and released a new control panel to market.

FS-Elliott has two compressor product lines, the Polaris+ and the PAP Plus. Polaris+ air compressors serve customers in industries such as food and beverage, textiles, industrial manufacturing, plastics, and power generation. The PAP Plus line is mostly utilized in oil refining, petrochemical, and LNG production and transport. It offers compliance to API 672 and API 614 standards. The company is also active in the air separation industry, where both of its compressor lines are used. 

The PAP Plus A1 is FS-Elliott’s workhorse compressor for oil and gas. Primarily used as an instrument air compressor, the A1 is available in cost and short lead-time pre-engineered configurations to meet API 672/614 with critical reliability features. The A1 can be customized to meet specific requirements to ensure year-round reliability and operation. 

Curtin commented that compressor life-cycle costs are generally organized into three groups: capital investment or purchase price; maintenance; and energy usage. When purchasing a new compressor, the primary focus is generally on the purchase price. Over the life of the compressor, that is typically the lowest cost. Energy costs are the highest, followed by maintenance. The other impact to consider is the effect the air source can have on the finished product. 

“Oil-flooded compressor air sources use expensive separation systems and can leave trace amounts of oil that can transfer to the finished product,” said Curtin. “For those producing textiles, food products, or medicines, any potential for oil contamination is unacceptable.” 

He recommends that audits are performed on existing compressed air systems by a company certified by the Department of Energy AirMaster+ Program or that completed Compressed Air Challenge training courses for compressed air systems. The return on investment of an air system audit can be immediate based on what is uncovered during the process and the final recommendations. One example is an automotive component manufacturer in North Carolina that saved $100,000 per year on electrical usage and $25,000 per year on annual maintenance costs by converting three oil-flooded rotary screw compressors to a more efficient oil-free centrifugal compressor.

FS-Elliott offers a range of control systems, including both microprocessor-based and PLC solutions. Its control panels support needs ranging from a basic user wanting to turn the compressor on and let it run without worry to more complex solutions encompassing redundancy and monitoring of every characteristic of compressor operations. 

The new FS-Elliott R2000 control panel features improved energy efficiency and a better user experience while reducing downtime. On the energy savings front, an Energy Advisor makes suggestions to improve efficiency based on operating trends. Its maintenance notification system tracks compressor usage and provides predictive maintenance advice.

The FSE-TurboCool line of fluids feature extended fluid life, wear protection, and resistance to foaming. FSE-TurboCool and FSE-TurboCool HD are ISO 32- and ISO 46-grade lubricants selected based on coolant temperatures and environment. FSE-TurboCool FG is a food-grade version of a 32-grade lubricant created to meet H1 requirements for fluids with incidental food contact (FDA 21 CFR 178.3570). FSE-CentriMax is a 32-grade premium mineral oil and FSE-TurboCool CC cleans heavily varnished air compressors while the unit remains in operation.

FSE-TurboCool uses an ester-based lubricant suitable for use in all centrifugal compressors and offers advantages over glycol-based lubricants. “In most glycol-based lubricants, a secondary oxidative inhibitor must be added to capture water and aid in water separation, which deactivates over time,” said Curtin. “FSE-TurboCool’s oxidative resistance offers long-lasting protection against deposits and varnish, enables moisture buildup from condensate to drain, and improves the efficiency of the compressor’s mechanical components.”

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Vendor spotlight: FS Elliott

Hydrogen – the world’s lightest and most abundant element – has been touted as a solution to radically decarbonize industries and societies. Several countries have included it in their medium and long-term emissions reduction plans, with the likes of Canada, France, Germany, and Japan rolling out strategies specific to hydrogen. 

To spur mass adoption of this zero-carbon molecule, a more robust supply chain is necessary. However, cost is a major barrier. Certain methods of hydrogen production, storage, and transport are specialized and expensive, especially when compared to more carbon-intensive alternatives. 

One way to make hydrogen more economically viable is to significantly scale demand. The installation of a single 400 MW, 100% hydrogen-fired gas turbine combined cycle power plant, for example, would use the same amount of hydrogen as 2 million hydrogen fuel cell vehicles. Such a shift would generate enough impetus to expand the build-out of hydrogen-related infrastructure.

Energy sector players need not start from scratch to ramp up hydrogen utilization. They can use existing gas power infrastructure. For decades, the energy sector has already successfully used hydrogen in various proportions within small gas turbines. The next step is to develop larger machines that can safely deploy hydrogen for utility-scale power generation. To date, there has been success in converting large gas turbines with dry low-NOx combustors to run with a 30% hydrogen and 70% natural gas mix. Exclusive hydrogen-firing is projected for 2025. 

Conversion of legacy systems to accommodate hydrogen firing can be done with minor structural modifications. Piping and valving sizes must be increased given the greater volume of hydrogen needed. But the compressor, turbines, and other auxiliaries can remain largely the same. 

To ensure the safe deployment of hydrogen in large-scale power generation, the combustor design has been reimagined. Most existing large gas turbines can run with up to 20% H. But as its proportion increases, hydrogen’s explosive nature and wide range of flammability must be addressed. One notable effect of the significant rise in temperature with hydrogen combustion is the increase in formation of NOx. 

A higher incidence of NOx emission can be mitigated by premixing fuel and air before entering the combustor. However, doing so poses a new challenge. Adding hydrogen raises the combustion speed of the fuel mix. It accelerates flame propagation to the point where it may exceed the fluid velocity of the premixed gases. This increases the risk of flashback – where the flame moves upstream in the fluid and can ignite fuel outside the combustion chamber.

A dry low-NOx combustor with an improved swirler nozzle has been developed to mitigate this challenge. Air is injected from the tip of the nozzle, increasing the velocity at the center of the swirling flow. This design boosted flashback resistance while enabling low-NOx combustion.

The energy sector can help drive demand for hydrogen, but it cannot act alone. Leaders in both public and private sectors can take steps to stimulate hydrogen demand and supply, while striking a balance between economic feasibility and environmental performance. 

The existing hydrogen supply chain is not decarbonized. With the bulk of commercially available hydrogen derived from fossil fuels, the IEA estimates that hydrogen production generates 830 million tons of carbon dioxide annually. This is equivalent to the combined CO2 emissions of the UK and Indonesia. 

There are several ways to produce hydrogen that can drastically reduce or eliminate carbon from the process. This includes pyrolysis of hydrocarbons (forming solid carbon as byproduct) as well as using steam reforming systems with carbon capture capabilities. Another option is to generate green hydrogen using renewable power. The rapid growth of renewables in several places has led to oversupply, forcing power producers to curtail renewable power generation or sell excess power at a loss. In theory, this surplus electricity from renewables can be harnessed to power electrolyzers to produce carbon-free hydrogen. 

However, to make green hydrogen competitive at scale, capital expenditure and operating expenses need to go down. The European Commission estimates that hydrogen derived from fossil fuels costs about $1.80 per kg, whereas green hydrogen ranges between $3.00 and $6.55 per kg. 

To bring hydrogen further down the value chain, suitable transport and storage systems are also needed. Traditionally, hydrogen is stored in tanks at high pressures (350 to 700 bar) and low temperatures (below -252.8°C). These extreme conditions mean that tanks must be specially designed, with large compressors enabling such processes.

Salt caverns, such as those used by the Advanced Clean Energy Storage project in Utah, present a viable alternative for hydrogen storage. When operational, the system will be integrated with existing power grid infrastructure in the Western U.S. and provide up to 1 GW of renewable energy that can be tapped year-round. 

Ammonia, which is easier to transport at scale than hydrogen, is also advancing the development of a hydrogen ecosystem. Not only can it be used directly as a fuel in smaller power systems, but it has proven to be an effective hydrogen carrier. In Australia, the Eyre Peninsula Gateway project is set to generate up to 40,000 tons of green ammonia per year and will feature a 75 MW electrolyzer for green hydrogen production.

Various parts of the world are at different stages of hydrogen adoption. In Europe, first-generation hydrogen projects are set to come online within the decade. These include the conversion of a 440 MW gas-fired power plant in the Netherlands to 100% hydrogen firing, as well as the development of a green hydrogen cluster in Hamburg. The U.S. has been leading the way in exploring hydrogen for energy storage, with ongoing projects and evaluations in Utah, New York, Virginia, Louisiana, and Texas. In Saudi Arabia, work is underway for a facility that will produce, among others, 650 tons of green hydrogen per day. 

In developing markets, limitations to infrastructure and access to capital are more acute. These countries can scale hydrogen adoption with blue or gray hydrogen and pair hydrogen production systems with carbon capture technologies. 

At the end of the day, the development of a global ecosystem for affordable hydrogen production, storage, transportation, and utilization will need partnerships across sectors and industries. One example is HyDeal Los Angeles where the local government is working with industry players to drive down the cost of green hydrogen to $1.50 per kg.

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How the energy sector can lead the hydrogen revolution. 

The economics of hydrogen

Now that coal plant emissions have been largely curtailed across much of Europe and North America, attention is swinging onto gas turbines. Such plants, by and large, do a good job at reducing emissions such as NOx and SOx.

"Power producers have already made great strides in lowering the carbon intensity of the power sector in the U.S., largely due to retiring coal and replacing it with a combination of natural gas and renewables,” said Evan Canady, Mitsubishi Power.

However, the current demand is that gas-fired plants greatly reduced their carbon emissions. This can be accomplished either by pre-combustion carbon separation (usually using methane steam reforming to syngas with subsequent water shift and CO2 removal) or post-combustion flue gas CO2 removal. 

The big hurdle, of course, is cost. Current technology is expensive and energy intensive. Not only is the carbon to be captured, it also needs to be stored somewhere and increasingly utilized in some process. Hence the term carbon capture utilization and storage (CCUS). (Note: It is also sometimes called CCS. 

Most attention, to date, has been lavished upon solvent-based capture i.e., the gas stream is exposed to a liquid medium to absorb CO2 via some kind of physical or chemical mechanism. Regeneration is also needed to break absor-bent-CO2 bonds.

Drawbacks include high energy consumption, corrosion, difficulties in scaling, and raw economics. Why spend money to develop and implement the technology in an environment that shows little love for fossil-based fuels. Nevertheless, advances have been made. Amine-based solvents from Mitsubishi have been used in the Petra Nova facility in Texas. Shell Global’s CanSolv is another solvent being used at the Boundary Dam project in Canada. Similarly, physical absorption solvent breakthroughs have been made such as Lurgi’s Rectisol process using chilled methanol as a solvent. Further areas of development include: solid sorbents are being developed by Svante in conjunction with Chevron and others; the Polaris membrane by Membrane Technology and Research in collaboration with the U.S. Department of Energy; SES Innovation’s cryogenic carbon capture; and FuellCell Energy’s fuel cell technology for carbon capture, using electrochemical membranes to separate CO2 from industrial waste gas streams. Further, Chart Industries (owner of LA Turbine) has developed Cryogenic Carbon Capture (CCC) technology. The cost to produce cement and capture CO2 using CCC technology is said to be 24% higher than producing cement with no capture.

Another approach is direct air capture (DAC) to strip CO2 from air using chemical and physical processes. Those working on this include Climeworks with a plant in Switzerland and Carbon Engineering from British Columbia, Canada, that plans to build a Permian Basin facility that to capture a million tonnes of CO2 per year by 2024 using a high-temperature aqueous method based on potassium hydroxide. Global Thermostat, too, has pioneered a porous, honeycomb ceramic approach to carbon capture. 

According to IDTechEx, capturing a tonne of CO2 directly from the atmosphere costs between $600 and $1,300 using current technology, compared with approximately $40 to $80 for capturing a tonne of CO2 from the flue gas stream of a coal-fired power plant. Despite that, the analyst firm forecasts that DAC is likely to gain a growing share of global CO2 capture capacity over the next few decades.

Wherever you turn, there are contrasting views concerning carbon capture. Some see it as entirely feasible, some as completely impractical, and others are somewhere in the middle.

Geert Laagland, Head of Engineering at electricity and district heat utility Vattenfall, said high upfront costs for CCUS means it is only going to be viable if a plant is going to run a lot of hours.

Mark Axford, Principal at Axford Turbine Consultants believes that CCUS represents a more credible path to lower emissions than the ongoing love affair with hydrogen. 

“Carbon capture of natural gas is probably a far more economical path than trying to convert everything to 100% hydrogen,” said Axford. 

“Post-combustion CO2 removal is technically viable but impractical because of the large volume flow and the need for high ratio CO2 compression,” said Klaus Brun, Director, Research and Development, Elliott Group. 

Let’s hear from the OEMs on how they plan to overcome the technical and overcome hurdles present in CCUS.

According to Arja Talakar, Senior Vice President, Industrial Applications Products, Siemens Energy, the critical element in CCUS is early engagement. With carbon capture, that means engaging early in the pre-FEED and FEED study stage. 

“The most successful CCUS projects will be those where the OEM and the developer have optimized cycle performance with machinery economics and considerations,” said Talakar. “While there are few commercial projects right now, many projects are being discussed and evaluated.” 

Siemens Energy is collaborating with BASF on proton exchange membrane (PEM) electrolyzers for hydrogen pro-duction with an output of 50 megawatts and the possibility of modular capacity expansions. It is also working with Aker Carbon Capture to develop carbon capture solutions that can be applied to gas turbines and gas-fired power plants. 

“New turbines and CCUS can provide sustainable solutions for the 21st century,” said Talakar. 

Why aren’t there more carbon capture projects addressed to natural gas-fired power facilities? He believes coal gets all the attention as it is dirtier and there represents the low-hanging fruit. He out-lined three points to bring down the cost of carbon capture projects associated with a combined cycle gas turbine (CCGT):

Be as efficient as possible to reduce the quantity of CO2 to be captured.

Reduce the temperature of the flue gas to reduce the need for cooling before capture.

Increase the concentration of the CO2 in the flue gas. 

Siemens Energy is conducting optimization studies with Total and others on ways to reduce CO2 emissions, focusing specifically on natural gas liquefaction facilities and associated power generation.

“To reach a 50% reduction in CO2emissions by mass, you need about 80% volume of hydrogen fuel content,” said Talakar. “While it isn’t economically viable today to operate large gas turbines at this level of hydrogen fuel mixture, these levels are within reach with smaller gas turbines, especially when considering hydrogen flare gases from petrochemical sources.” 

Adding 10% volume of hydrogen to natural gas will reduce CO2 emissions by 2.7%. A 600 MW combined-cycle power plant that runs 6,000 hours a year at 60% efficiency would equate to a reduction in approximately 1.26 million metric tons of CO2. In Brazil, for example, the company has two SGT-600 turbine generator sets operating on residue gas with high hydro-gen content at a cogeneration plant. 

“Compressors can be used to safely and cost-effectively transport and store CO2 or hydrogen,” said Talakar.

Alongside several companies led by Highly Innovative Fuels (HIF), Siemens Energy is developing and implementing a commercial large-scale plant in Chile for the production of e-fuel (synthetic methanol for e-diesel, e-gasoline, or e-kerosene). Electrolyzers use wind power to split water into oxygen and hydrogen via Proton Exchange Membrane (PEM) electrolysis CO₂ is captured from the air and combined with hydrogen to produce methanol. About 40% of the methanol is converted into synthetic gasoline.

Atlas Copco Gas and Process has been involved in CCUS for about 15 years, supplying compression equipment for a variety of applications. It is currently seeing increased activity in the utilization of supercritical CO2. 

“Many major players want to continue operating their fossil-based processes so they are putting more focus on capturing and using CO2,” said Ulrich Schmitz, Marketing Manager at Atlas Copco Gas and Process. Some developed countries are not only sequestrating the CO2, they are utilizing it to produce consumer goods such as blending it with hydrogen to make methanol.” 

Most R&D focuses on two main types of CO2 utilization, he said: Using existing and available CO2 molecules for CO2post-combustion processes (oxy combustion); and blending CO2 with hydrogen to create methane or methanol.

CO2 has special characteristics and challenging properties such as a heavy mole weight gas and abundant volume. Centrifugal machinery, therefore, is a very good fit to process it, particularly integrally geared compression which is a high head technology. In addition, it pro-vides a favorable pressure ratio as well as intercooling.

MAN is another company with extensive experience in CO2 compression – more than 20 years. Out of 18 large-scale facilities in commercial operation around the world, eight use MAN’s CO2 compression technology. For instance, MAN’s RG integrally geared compressor has been deployed at a commercial-scale CCUS project to tackle carbon emissions at an oil-sand operation in Alberta, Canada. Shell’s Quest plant has captured and injected more than one million tons of CO2 underground annually since 2015.

"Power, heat generation and industries like cement and steel production are responsible for approx. 60% of all CO2 emission and thus are the focus of decarbonization,” said Peter Klotzsche, MAN Energy Solutions.

The company has signed a technology-cooperation agreement with Aker Carbon Capture to provide new energy-efficient compression solutions for CCS applications with heat recovery. Further, it supports CO2 utilization applications for urea production, Enhanced Oil Recovery (EOR), methanization, synthetic fuels and methanol production with compression and reactor technologies.

The Baker Hughes take on CCUS is that there is no single solution. The approach to carbon capture on an offshore natural gas platform, for example, would vary from a carbon capture design for a refinery or a cement plant. Accordingly, the company has several arrows in its CCUS quiver. It acquired Compact Carbon Capture, which uses a rotating bed technology instead of static columns to dis-tribute carbon capturing solvents in a compact and modular format. It secured the exclusive license of SRI’s Mixed Salt Process, a solvent process that uses potassium and ammonia. In addition, it is examining how the chilled ammonia process (CAP), which uses aqueous ammonia as a solvent, can capture carbon dioxide from mid- to large-scale industrial sites and other sources of CO2 emissions.

“We’re also engaged in the Borg CO2 carbon capture project in Norway, which is centered on an industrial cluster approach,” said Chris Barkey, Chief Technology Officer, Turbomachinery & Process Solutions, Baker Hughes. “Separately, we are working with Horisont Energy to find optimal technologies for an offshore lower-cost carbon storage project named Polaris in Norway, part of the Barents Blue ammonia production project.” 

Most recently, Baker Hughes announced an investment in Electrochaea, a company developing bio-methanation technology which enables CO2 recycling into grid-quality, low carbon synthetic natural gas (SNG), contributing to decarbonization of hard-to-abate sectors, such as transportation and heating. In conjunction with Baker Hughes post-combustion carbon capture technology including Compact Carbon Capture, Electrochaea’s bio-methanation technology can help develop and commercialize an integrated carbon capture and utilization tailored to applications utilizing CO2 sources with biogenic origin (biomass, waste-to-energy), as well as sources based on combustion of fossil fuels. 

To reach net-zero for large-scale natural gas plants, Barkey added that CCUS technologies must address exhaust gases. The company is investing in post-combustion carbon capture solu-tions for gas turbine exhaust gas applications. An alternative approach is to redesign turbines to produce fewer emissions. The LM9000 aeroderivative gas turbine, for example, now has simple cycle efficiency in excess of 44%. 

“Efficiency is key to driving lower carbon intensity of the LM9000,” said Barkey. “It has been designed for 15ppm NOx emissions in dry condition.” 

“ The challenge of implementing large-scale CCUS will be to reduce the installed cost and minimize the operating costs,” said Chris Barkey, Baker Hughes.

Baker Hughes has been involved in CO2 compression since the 1960s where its first application was for urea synthesis. Today, it can pro-vide CO2 compression across a range of applications including reinjection of up to 550+ bars in almost pure form. It recently introduced a main compressor prototype for supercritical CO2 that is compact and high speed. It reached over 800 kg/m3 density at the discharge and operated just on the critical point of the CO2 at the suction.

“CO2 is a highly compressible gas so the main challenge we have been tackling is to build a compact, efficient machine which can deal with the huge aerodynamic forces acting on the rotor,” said Barkey.

Mitsubishi Heavy Industries (MHI) began developing CCUS technology over 30 years ago. It has an amine-based technology known as the KM CDR Process. It is used in the world’s largest post-combustion carbon capture facility, which was installed on a coal power plant in 2016. MHI was also selected as the technology provider for a feasibility study of carbon capture at Lehigh Cement Company’s Edmonton Cement Plant. This project is being jointly conducted by the International CCS Knowledge Centre and Lehigh Cement with a target delivery of fall 2021. It has received support from Emissions Reduction Alberta. The capacity is estimated to be 600,000 tonnes of CO2 annually.

Additionally, MHI and Drax Group agreed to a long-term project for Drax to use the company’s carbon capture technology in combination with MHI’s KS-21 sol-vent at Drax’s power station in Yorkshire, U.K. A further element is offshore geological storage under the North Sea. MHI also has commercial experience in carbon capture of natural gas boiler exhaust. The applications are predominantly for chemical production such as methanol or urea. NextDecade Corporation, too have signed an agreement with MHI to use KM CDR Process post-combustion technology in gas turbines at the Rio Grande LNG project in Texas. 

“A number of confidential studies are underway focused on natural gas boiler exhaust as well as natural gas turbine exhaust with the goal of sequestering the CO2 or utilizing it,” said Evan Canady, Senior Business Development Manager, Renewable Fuels, Mitsubishi Power.

GE has developed many projects using amine technology and chilled ammonia in Europe and North America to remove CO2 post-combustion. While tradition-ally applied to coal plants, these technologies can be applied to natural gas power plants. 

There are plenty of opportunities, too, in CO2 compression at the capture site, along the transportation corridor, and the injection site. At a power plant, for example, the CO2 needs to be dried of any moisture, and compressed to 70 – 80 bar for pipeline transportation. At the well head or injection point, booster compression is often needed to increase pressure for injection into the Earth’s crust. 

“Most new CCS project requests tar-gets natural gas power,” said John Catillaz, Director of Decarbonization – Marketing GE Gas Power.

CCUS deals primarily with the separation and sequestration of carbon dioxide either pre- or post-combustion from a hydrocar-bon power plant fuel or from an industrial process that emits CO2. The most com-mon forms of separation are pre-combustion from synthesis gas in a gasification plant, post combustion from flue gas, and blue hydrogen production from natural gas reforming. Thus, CCUS can also require compression and pumping of synthesis gas, hydrogen, nitrogen, oxygen, natural gas or other gaseous feed-stocks. Elliott Group manufactures centrifugal compressors that can be utilized for the compression and transport of carbon dioxide and any of the other gases of the various CCUS processes. The company has several ongoing R&D activities that focus on the improvement of compressors for CCUS as well as the development of new products. 

Most of the discussion of CCUS for natural gas-fired turbines is directly related to the production of blue hydro-gen. Blue hydrogen can be either produced near a hydrocarbon source and then transported to the plant via pipeline or the hydrocarbon can be transported to the power plant using existing infra-structure to be converted to blue hydro-gen near the power plant consumer site.

"Most new CCS project requests targets natural gas power,” said John Catillaz, GE Gas Power.

“The latter option appears more practical since it avoids the cost of having to develop an entirely new hydrogen transportation infrastructure,” said Klaus Brun, Director R&D, Elliott. “There are three value streams in blue hydro-gen-based CCUS: Natural gas, hydrogen, and carbon dioxide.” 

Elliott is currently working with several end-users and operators throughout the world to develop customized com-pression solutions for blue hydrogen pro-duction. This includes Elliot’s Fex-Op compressor arrangement which can be utilized for both hydrogen transport and CO2 applications as well as the company’s existing line of TCH140H pipeline compressors for natural gas compression. 

“Post-combustion carbon capture tends to be significantly more challenging and costly than pre-combustion separation because of the low concentration of CO2 in the flue gas,” said Brun. 

Elliott has been in discussion with process developers to provide the high pressure ratio compression solutions required to take near-atmospheric flue gas CO2 to pipeline and injection pressures.

In 2020, there were 26 commercially active CCUS projects in the world, representing a carbon capture capability of approximately 40 million tonnes per annum (Mtpa). Currently, there are a handful of other CCUS facilities currently under construction, with a few more in advanced development and several more in early development. However, these facilities collectively represent less than 100 Mtpa of carbon capture capacity set to come online. That is far from enough to satisfy the goals set by bureaucrats in Europe and the U.S. 

Whether pre- or post-combustion, or some other approach entirely, comes to dominate, what is certain is that more projects are very much on the horizon. As well as those noted above, LNG exporters Cheniere Energy and Sempra Energy plan to add CCUS capabilities to U.S. LNG projects. This may be in response to an order cancellation from France which claimed U.S. LNG was too dirty. Sempra’s Port Arthur LNG terminal in Texas and Cameron LNG plant in Louisiana are being looked at for CCUS, as are Cheniere’s Corpus Christi plant in Texas and Sabine Pass terminal in Louisiana.

 Meanwhile, Venture Global LNG intends to capture and sequester carbon at its Calcasieu Pass and Plaquemines LNG facilities in the U.S. After compressing CO2, it will be transported and injected into subsurface saline aquifers. The goal is half a million tons of carbon per year. ExxonMobil, too, has announced plans for deep storage of carbon in the Gulf of Mexico. 

“We have committed real dollars to development and engineering,” said Cheniere CEO Jack Fusco. “Customers are going to expect us to continue to offer a sustainable LNG product.”

Lowering carbon emissions from gas turbines. 

Carbon capture

Gas turbine fuel control has become more important than ever. Whether due to emissions mandates, maintaining efficiency, plant profitability or increasing the lifespan of a facility, operators and owners are looking for ways to achieve a tighter rein on fuel usage. Here are the top five reasons why now is a good time to upgrade your fuel system.

There are a great many gas turbines around that have been in operation for ten, twenty, thirty or more years. Machines that have been in heavy use are likely to have worn fuel valves, unreliable shutoffs, or systems that aren’t responsive enough to operator instructions. But even peaking turbines that have seen infrequent usage can suffer badly due to faulty fuel control systems or components. 

As these units age further, components wear. This can lead to problems in starting up the machine as well as unscheduled outages and maintenance personnel continually having to babysit the fuel controls. 

Additionally, there are many turbines out there with fuel control systems that are either poorly supported or have been made obsolete by the OEM. There comes a point when it becomes too much of a burden to continually scramble to find components or keep aging controls running.

In this day and age, speed is everything. Operators demand turbomachinery that is going to start up rapidly on demand, and shutdown instantly should problems arise. The fuel control system must match these expectations. This means valves that provide the precise fuel mix and fuel shutoffs that do the job in a timely manner. 

Yet fuel controls don’t always measure up. In some cases, aging facilities have installed manual ball valves to keep their fuel control systems running. There is no place for such technology in a modern gas turbine plant. Even standard fuel control systems may not be good enough for current conditions. Response times of half a second to a second (and as much as two seconds for a slow motor) are commonplace. Such systems operate at risk. 

Pneumatically actuated valves are required with response times of 200 milliseconds or less. Only then, can the operator have peace of mind that shutoffs will occur rapidly enough to avoid damage. Furthermore, pneumatic systems are available that only need 1 amp at 24 volts DC. 

Fuel metering valves must also be able to function at the right pace. All-electric fuel control valves offer real-time flow control to dispense the right amount of fuel at the right time, as requested by the turbomachinery control system. This has everything to do with achieving performance objectives, while avoiding the possibility of falling out of emissions compliance.

Not so long ago, plants operated with large teams of skilled operations and maintenance personnel. But the demand to do a lot more with far fewer personnel has drastically shifted the skills picture in facilities. Couple that with an aging workforce with a steady parade of retirements and there is no place for finicky or unreliable turbine systems. 

Fuel controls, therefore, must not be the weak link. Instead of being composed of multiple components cobbled together over the years that require constant attention, they must be unified into one comprehensive, automated fuel metering, shutoff, and control system. Ideally, such pre-assembled systems would include electric actuation at low power to eliminate the need for additional high-powered electrical lines to be fed into them to operate motor-driven valves. It is even possible to operate the fuel control valves at the same pressure as the incoming gas. 

Such systems ease the burden on less-experienced plant personnel by offering them an engineered solution that is tested, integrated, and can be dropped in place. Veteran staff may be able to purchase the various components and competently tie everything together – if they have the time. But the generation entering the workforce demands fit-and-forget, leak-free systems. They want to spend their time on the big picture – overall performance, plant economics and emissions compliance – not in the routine of adjusting valves, checking for leaks, and troubleshooting fuel control issues.

Standards are continually evolving. Safety standards have altered markedly over the last twenty years. These days SIL 2 or 3 safety levels are the norm for new valves. Fast shutoff of fuel to the gas turbine is another aspect of safety. The flow of gas must cease immediately as dictated by plant control systems or whenever there is a loss of pilot pressure.

 Older systems lack the safety capabilities of the latest fuel controls. The latest systems offer redundant pneumatic shutoff valves, and a block-and-bleed architecture to prevent leaks. In addition, they offer pilot valves: A spring-loaded piston is activated by system pressure to open the valve; when pressure is released, the valve closes at once. This safety feature is an important fail-safe mechanism. Those relying on all-electric systems, however, can experience shutdown delays in the event of a power cut. 

There are plenty of other standards that apply. Those wishing to operate in Europe must meet ATEX requirements, which are steadily refined. In North America, valves, components, and systems are subject to ASME certification. Similarly, emissions regulations become ever more stringent. Gas turbine operators must maintain NOx and other emissions below regulated limits. More recently, gaseous methane compliance has been added to the compliance burden. 

Older fuel controls are found lacking when it comes to some of these standards. They struggle to remain in compliance and lack the flexibility to deal with shifts from high BTU to low BTU fuel, or vice versa. However, systems are available with complete fuel control assemblies fully certified and tested to meet local requirements.

Inefficient fuel systems exert a significant impact on plant performance and profitability. The ability to rapidly start, stop and adjust the various elements of fuel control translates directly into improved economics and an ability to meet market demands. Older systems lack the necessary degree of responsiveness. 

Component or system unreliability opens the door to unexpected shutdowns. This can mean the difference between a profitable and unprofitable facility. Those investing in modern, end-to-end fuel controls gain more certainty of performance. With that comes lowered risk and more predictable economic outcomes.

The Gas Fuel Shutoff and Control System from Continental Controls is a complete fuel train inclusive of fuel metering, redundant pneumatic shutoff valves that meet safety and other industry standards, pilot valves, flow measurement, NOx feedback, fuel heating value measurement, and gas leakage elimination via a coaxial valve. This integrated system includes a controller with sensors for temperature, pressure, and other parameters. All components are preassembled, welded, tested, certified, and delivered on one manifold. 

The design allows for precision flow, pressure, or position control measurement even with changing backpressure or other effects from the application that may cause other measurement techniques to be less accurate. Fuel flow measurement, for example, is available to the user for control, display, and logging purposes at ±2% reading accuracy or 0.5% of full scale, whichever is greatest. Fuel flow control is conducted by an electronic computer assembly. This computer receives the 4 to 20 mA fuel demand signal and compares it to the fuel flow signal from the built-in flowmeter. It then adjusts the throttling orifice to change the fuel flow as necessary to make the measured fuel flow equal to the fuel demand. Control is based on mass flow calculation, not just pressure or position. 

It provides fire-safe and fast natural gas shutoff, is SIL 2 to 3 certified, and can close in less than 200 milliseconds. The system is pressure tested with valves that close bubble tight with loss of pilot pressure. This integrated solution is suitable for operators and repackagers looking to repair or replace an existing fuel system on gas turbines up to 50 MW.

Five reasons why you should upgrade your fuel system. 

Turbine fuel control


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 


Old-fashioned reciprocating compressors have been used in high-pressure services for decades. They have been unreliable, inefficient, heavy, bulky, and wasteful. Modern plants and facilities use vertically-split, dry-gas sealed, shear-ring head centrifugal compressors for high-pressure services (>150 Barg). 

Modern high-pressure turbocompressors should be engineered, manufactured, and operated with a special focus on critical areas such as: rotordynamics, thermodynamics, potential dynamic excitations, rotating-stall, auxiliary systems, fabrication processes, and dry-gas seals. Some examples of high-pressure turbocompressor applications are hydro-cracking, hydrogen-rich process gases (such as those in refineries), methanol plants, gas reinjection (or gas injection), high-pressure transportation pipelines, and some petrochemical processes such as polyethylene processes. High-pressure turbocompressors will continue to play important roles in different industries in the future. Today, competent vendors are capable of manufacturing centrifugal compressors with discharge pressures of more than 900 bar.

A vertically split casing with a heavy bolted head is a classic configuration for medium pressure centrifugal compressors. However, this is not practical for high-pressure turbocompressors because there is not enough space on the casing head for the heavy bolts required. The common configuration for modern high-pressure turbo-compressors is the shear-ring cover head that eliminates the bolts at the compressor head. The end covers are retained by the shear-ring segments. The casing is generally forged from a suitable grade of steel. 

High-pressure turbocompressors generally use closed-type three-dimensional impellers. Both the efficiency and the pressure coefficients are higher for three-dimensional impellers compared to conventional ones. Impellers are usually manufactured from low-alloy steels. In-depth material and metallurgical investigations are needed to examine and evaluate the material integrity regarding various failure modes such as sulfide stress cracking (SSC) and others. 

One of the major problems is that even after the transition of the gas to the dense phase, water can drop out if the gas is sufficiently cooled. For instance, SSC can occur in minutes if a susceptible material under sufficient stress is exposed to a wet sour condition in any wet upset.

For high-pressure turbocompressors, the thrust force generated in the impeller assembly is much greater than can be handled in a thrust bearing. Therefore, the thrust forces should be balanced by using double-entry impeller series (a back-to-back arrangement) and balance piston(s). A recommended configuration is a back-to-back impeller arrangement with two balance pistons. The remaining axial (thrust) force is the difference between the forces which are a magnitude larger. A double-acting tilting-pad thrust bearing should be used. 

September/October 2021