Markus Seibold, Vice President of Additive Manufacturing (AM) at Siemens Power Generation Operations, discusses 3D prin ing, advanced manufacturing, innovation and how to make turbomachinery more competitive in the coming years.

What role will 3D printing play in turbomachinery development?

AM offers a way to improve performance while lowering emissions. It can enable us to be far more competitive in terms of cost, lead times and development times. And it offers a pathway to better business models such as being able to make spare parts on demand rather than having to spend a fortune to build up a vast inventory of every component for every machine in the field.

How can it help improve turbomachinery service and repairs?

There are many gas and steam turbines out there from the eighties, nineties and even earlier. In many cases, parts are either difficult to find, or simply no longer exist. Yet many of these turbines continue to operate and need parts availability. AM gives us the ability to either 3D print those parts from existing drawings or reverse engineer them using 3D scanning. In many cases, we can actually make a better part than the original.

We have the Siemens 9000 HL engine in development. Its combined cycle efficiency will be pushed beyond 63% by including additive parts that could not be made otherwise. These new parts have complex geometries and intricate cooling paths that would be impossible to cast. Another benefit of AM is speed of development. In the past, it perhaps took six or seven years to bring a new turbine to market. We can half that today with parallel development of technologies, rapid prototyping, virtual reality simulation of different parts and AM.

Vanes used to take us 18 to 24 months to develop the concept, design, cast, test and implement in production. Now, we can do it all in three months. Simulation enables us to compare different designs and pick the best instead of wasting time developing prototypes for each. We may still cast the final part, but we can select the best design with 3D printing.

Yes. While the technology will be used in gas turbines to enhance performance and lower emissions, we expect steam turbines to benefit more through obsolescence management and spare part availability. We can use AM to make valves that are no longer manufactured, solve supply chain issues and ease the strain on inventory.

Our 3D printing facility in Sweden already produces some 3D printed parts for Siemens centrifugal compressors. This is helping us to drive more AM technology into our compressors, while enabling us to develop materials and parts that can cope with higher temperature operation.

We are very involved in cross-industry collaboration to advance AM technology. Traditionally, Siemens Gas & Power only looked at the energy market and developed components for itself. Fields such as aerospace did the same. Collaboration was rare. Yet everyone has similar challenges in materials, component durability and cost. Thus, we are actively working with people in aerospace and other areas to design new processes, develop the best materials, produce better components and then industrialize them to scale. Looking ahead, it is vital that we develop strong and lasting partnerships in innovation. In some cases, the intellectual property (IP) will be ours and in others it will belong to a partner in aerospace. But we envision jointly developed IP, too. By bringing different mindsets together, great opportunities can happen. Active engagement with other companies can greatly speed the pace of development and innovation.

Siemens acquired Materials Solutions a couple of years ago but runs it as an independent company. This provided us with immediate know-how to apply AM to turbomachinery instead of having to spend many years trying to figure out 3D printing within Siemens. Materials Solutions brings +12 years of AM experience to the table. In collaboration with Materials Solutions, we have created a new Innovation Center in Orlando to develop new 3D printing processes, materials and application.

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Siemens Gas & Power bets on innovation

As renewables such as wind and solar continue to ramp up in the U.S., the need for faster start-capable grid augmentation is on the rise. In the Heat Recovery Steam Generator (HRSG) realm, many new unit construction projects are touting fast-start capabilities. Early-to-mid 2000s combined cycle plants are struggling to stay relevant in an ever-changing market.

A combined cycle plant in California, for example, succumbed to the renewable push by indicating it plans to shutter its doors nearly 20 years prior to its design end-of-life. The closure is a result of legacy technology that made the plant no longer economically viable. What can other mid-life plants do to stay relevant into the 2020s and beyond?

A smart place to begin is with a review of start-up procedures to determine bottlenecks that might exist in the sequence. For one plant, the need for steam turbine seals kept them from bypassing steam to their condenser early on. An earlier source of steam using an existing let down station was identified. This cut about 20 minutes off the start-up timeframe. Another fruitful area to investigate is gas turbine purge time.

In many cases, GT OEMs use a conservative time-frame for their purge requirement prior to light-off of the turbine. Fifteen minutes is a commonly seen number. The National Fire Protection Association (NFPA) Section 85 code requires, “at least five-volume changes at purge rate and for a duration of not less than 5 minutes.” There are also specifics on purge volume requirements and purge rate.

Analysis reveals that OEM time-frames are conservative and can likely be reduced. Several recent projects calculated the required purge time at a range of 5-to-8 minutes for F-Class sized HRSGs. If equipment and control upgrades are in place, it may be possible to eliminate the purge cycle altogether.

To satisfy the purge credit requirements, experience indicates that it is necessary to conduct a detailed review of the plant piping and instrumentation diagram (P&ID) surrounding the gas turbine, duct burner and emissions equipment valving. For most existing plants, this often means retrofitting triple block-and-bleed systems along with controls upgrades which make the purge credit cost-prohibitive unless it is factored in during new unit construction. For plants with Selective Catalytic Reduction (SCR) emissions technology, the ammonia flow control valve can be a start-up hindrance as it correlates to NOx emission block average requirements.

Gas-side temperatures at the inlet to the catalyst may not reach their permissive requirement (typically 480°F for natural gas operation and 550°F for fuel oil operation) until late in the startup due to steam turbine interaction.

For one plant no longer fired on fuel oil, collaboration with the catalyst supplier safely reduced the ammonia flow control valve setpoint from 550°F to 480°F, allowing it to meet emissions block average requirement on a more reliable basis. Additionally, ammonia vaporization on systems with hot gas recirculation (HGR) may become problematic. Find out if the start-up gas temperature at the HGR is hot enough to properly vaporize the ammonia. If not, is it possible to use an upstream (hotter) gas source during start-up to satisfy the vaporization equipment?

It is no surprise that the HRSG industry is dealing with more and more fatigue damage in high-pressure steam drums as a result of cycling load profiles and quicker starts. When the rate of pressurization changes quickly, large temperature gradients manifest at the inside/outside drum interface. If the temperature gradient becomes too large, stresses can start cracks at discontinuities like large downcomer and riser nozzles.

When looking at a steam table, a disparagingly large difference in saturation temperature is seen when comparing a cold start with a warm or hot start. For instance, the change in saturation temperature from 0 to 400 psig is about 236°F; from 800 to 1,600 psig is approximately 86°F. What does this mean? There is a larger potential for damage during a cold start compared to a warm or hot start.

Bottom line: Adhere as close as possible to your HRSG OEMs guidelines for cold start-up ramp rates. It is likely that OEM figures for warm and hot starts are conservative. If looking to optimize startups, therefore, consider implementing a system to monitor drum stress by measuring the rate of change of shell and nozzle temperature and using DCS alarms.

Performing a remaining life assessment may also provide valuable information regarding safe ramp rates and amount of weld fatigue life left. Tube metal temperatures continue to rise as gas turbines are upgraded and duct burner systems are pushed to the limit. Practically speaking, the tube metal temperature is a fraction of the steam/water temperature in the tube and the exhaust gas temperature acting on the outside of the tube. This means as gas temperature increases, so does the tube metal temperature. For large units, the first tube module typically experiences its highest metal temperature during start-up or low-load unfired operation.

In HRSGs with duct burner systems, the highest tube metal temperatures in the second module occur while the duct burner is operational (for those with a split superheater (SH) reheater (RH) arrangement. Most creep or overheating failures have been found downstream of the duct burner system. It is likely, then, that more failures are coming down the pike as duct burners continue to fire harder than ever.

One way to visually inspect for evidence of tube metal temperature problems is to look for oxide growth on ferritic pressure parts. Inspect superheater and reheater tubes looking for oxide layer growth. As tube metal temperature increases, so does the rate of oxide growth. Oxide insulates the tube wall, further driving the metal temperature up.

Key point: even a small (nominally 10°F) increase in tube metal temperature (from 1,070 to 1,080°F for Grade 22 steel or from 1,110 to 1,120°F for Grade 91) can reduce creep life by as much as 40%. Nameplate capacity Gas turbine upgrades affect more than just tube metal temperatures. Through analysis, it has been determined that HRSGs often increase steam flow in one or more pressure levels. In one case, a 2% to 5% increase in high-pressure steam f low warranted re-rating the stamped name plate capacity of the HRSG along with pressure safety valve capacities.

Moral of the story: If performing a gas turbine upgrade, do not forget to analyze the effect on downstream HRSG equipment. Questions to ask:

• Is there enough boiler feed pump capacity?

• Will the SH/RH tube/header metal temperatures remain within their design margin?

• Is the steam drum separation equipment still adequate with the additional steam flow?

• Are my safety valves able to relieve properly?

■ Jordan Bartol is Systems Engineer at HRST. Since 1998, HRST has specialized in technical services and product designs for heat recovery steam generators (HRSGs), waste heat boilers, and smaller gas/oil-fired power boilers globally. For more information visit hrstinc.com

Fast start and peak capacity considerations for combined cycle power plants

Natural gas from producing wells and storage facilities is typically pressurized to facilitate efficient transportation in pipelines across long distances. The pressure is stepped down at pressure letdown (PLD) stations at various stages across the network.

The PLD station depressurizes the gas to lower levels for safe delivery through local distribution networks such as local gas mains, smaller-diameter service lines and individual meters for industrial, commercial and residential end users. Pressure reduction is most commonly accomplished through the installation of Joule-Thomson (JT) regulating valves, which reduce the gas pressure to the desired level.

It consists of a mechanical valve, which is throttled to create the desired pressure differential between the inlet and outlet The JT PLD device is a simple and generally effective tool for pressure reduction, but a by-product is waste heat. A turboexpander and generator can be used to capture this waste energy.

The turboexpander generator reduces gas pressure and converts the resulting kinetic energy into electrical energy, which can be sold to the grid. Turboexpanders have been successfully deployed for energy recovery in air separation, refineries, geothermal power recovery, steam pressure letdown stations, turbochargers and gas turbine waste heat recovery, as well as in nitrogen, helium and hydrogen liquefaction.

However, such systems have had difficulty in attaining viability for natural gas PLD applications due to capital costs and operating expenses. Traditionally, the turboexpander uses a large gear box to adjust the speed of the expander turbine, which is coupled to a synchronous generator. It requires a lubrication system that includes an oil reservoir, pump cooler, filters and piping. Seals are needed to separate the lubricant from the high-pressure natural gas to prevent contamination. The lubrication system is the least reliable component in the overall installation, entailing ongoing maintenance. These drawbacks can be largely overcome through the use of new magnetic bearing technologies that eliminate the lubrication subsystem.

An alternate turboexpander system is known as the FreeSpin Inline Turboexpander (FIT). The hermetically sealed unit consists of an integrated high-speed turboexpander and a permanent-magnet generator, both driven by a single spinning rotor levitated on non-contact magnetic bearings. The direct-drive, permanent- magnet generator has variable speed and load capabilities and can run at rated speeds up to 30,000 rpm. The flow of the natural gas is used to cool the stator, rotor and magnetic bearings.

Since moving parts do not come into direct contact, there are no friction losses. No auxiliary lubrication system is needed. This eliminates risk of oil contamination, provides a smaller footprint and lower installation and maintenance costs.

1. The pre-heated high-pressure gas flows into the turboexpander

2. The gas expands through the radial turbine wheel

3. The low-pressure gas exits the turboexpander and is ready for flow into the distribution and delivery network for end users

4. The energy wasted during the pressure reduction process is recovered by the turboexpander and converted to electrical power

5. Any excess high-pressure gas not directed through the turboexpander is expanded by the conventional Joule Thomson pressure regulator, which is installed in parallel with the turboexpander

6. The produced electricity enters the Vericycle Bi-directional Power Electronics Unit, which can be programmed to specific power requirements.

Pressure drop is often accompanied by a temperature drop, and this can cause vapor condensation. As a result, the FIT system can include an inlet heating source (i.e., waste heat recovery). The flow through architecture of this system is scalable to approximately 500 kW.

Collaborating with Baker Hughes, a prototype 300 kW unit was built and tested at a PLD station in Bologna, Italy. The unit is designed for a life of over 10 years without maintenance. Based on preliminary data, Baker Hughes projects an estimated potential energy recovery of over 1.6 million kWh per year. ■

Freddie Sarhan is Vice President of Business Development at Calnetix Technologies, the developer of the FreeSpin In-line Turboexpander with many years of experience in turbomachinery and industrial ORC heat recovery systems. For more information, visit 

How to use your turboexpanders in energy recovery

Bently Nevada, part of Baker Hughes, pioneered the condition monitoring field in the 1960s. Its 3500 series hardware can be found in facilities around the world. BHGE chose TPS 2019 to unveil its next-generation platform, the Orbit 60 Series. It collects and processes data, equipping operators with analytics to determine the health of machines. It is designed with cybersecurity in mind.

“Current approaches to condition monitoring can sometimes be inaccessible,” said Terry Knight, President of Bently Nevada. “Orbit 60 is a digitally integrated and cybersecure system.”

One challenge Bently Nevada had was how to ensure machinery protection while still being able to share condition monitoring information widely. This required complete separation between the protection and the monitoring architectures. Accordingly, the new system has a built-in data diode — a method that enables secure one-way data transfer from the device to Bently Nevada’s machinery management software System 1 for monitoring and diagnostics.

“Even if hackers got into the condition monitoring system, they couldn’t get a signal down to the protection system,” said Knight. “They have no way to communicate to the protection side of the Orbit 60 due to the data diode.”

As well as cybersecurity, the platform complies to high standards of safety. It will be SIL 2 and 3 certified, and API 670 compliant. Extensive customer input was gathered to make improvements to Orbit 60 and provide it with the latest technology. As well as security upgrades, users wanted greater flexibility and for the system to measure a broader range of equipment.

Users can provide more sensors than before to add condition monitoring functionality. They will also be able to write their own rules and customize the software to their own needs. “We went around the world and discussed the 3500 platform with more than fifty customers to find out what they liked about it, what they wanted it to do differently, and what problems they faced,” Knight said.

It now offers 80 data channels compared to an industry average of 50. The company claims that it has 100 times more signal processing power and a smaller physical footprint than the industry standard. It can be placed inside an instrument cabinet or distributed throughout the plant. Operators can connect it to a wide range of assets. “Orbit 60 Series offers powerful analytics with enhanced flexibility and scalability, along with a built-in cybersecurity features, reducing overall investment cost, and giving operators full visibility of a plant,” said Knight.

Those with 3500 series devices and other Bently Nevada systems will find the Orbit 60 complementary. With over 85,000 of the 3500 racks installed worldwide supported by inputs from six million sensors, this platform will continue to be available and will be supported for many years to come, said Knight. “Orbit 60 can be deployed at the edge of the network to perform analytics specific to a particular piece of equipment, or that data can be transmitted centrally for overall fleet analytics,” he said. The initial release of Orbit 60 will enable it to connect to the System One software platform. Future releases will allow it to integrate with other software and systems. ■

Bently Nevada's first major condition monitoring platform in 20 years

An obvious objective is to confirm the compressor will perform as predicted. But an equally important goal is to minimize the risk of unexpected aero-mechanical issues during field installation, especially in remote locations such as offshore platforms. It is far better to uncover potential problems before the equipment leaves the original equipment manufacturer’s (OEM) facility.

High-pressure and high-power density compressors typically experience rotordynamic (instability) and aerodynamic (stall) complications more often than compressors intended for petrochemical service. Thus, the demand for more rigorous in-house testing has grown. In response, OEMs and the turbomachinery community developed a variety of test programs and facilities to demonstrate that equipment meets end-user requirements.

• Volume reduction, inert gas tests using small open- or closed-loops (typically called Type 2 testing according to PTC 10, “Performance Test Code on Compressors and Exhausters,” ASME International, 1997)

• Full-load, full-pressure, full-power testing with the contract drivers, gears, auxiliaries, complex piping systems, and so on (typically labeled Type 1 testing)

• Each type of test offers insight into a compression system’s aerodynamic and mechanical behavior. Type 2 low-pressure inert gas performance tests are set up based on compressor volume reduction (i.e., exit volumetric flow divided by inlet volumetric flow).

A critical parameter in assessing multi-stage compressor performance is the combined volume reductions of the individual stages to determine the overall volume reduction of the compressor. Thus, the volume reduction of stage 1 determines the volumetric flow into stage 2, which sets the flow into stage 3, and so on.

Volume reduction tests use readily available gases, such as nitrogen, helium- nitrogen mixtures, carbon dioxide and R-134A refrigerants. The selection of test gas or gases, operating speed, and so forth are made to match as closely as possible the volume reduction the compressor will experience in the field.

Type 2 tests are also run at lower pressures than the compressor will experience in field operation. A Type 1 test, per the ASME code, is run with a gas mixture close to the gas compressed at or near operating conditions expected at the site. If it is possible to conduct the test using the actual field gas and field inlet conditions there may be no deviations between the field and test conditions; however, this is rare.

In most instances, the inlet temperature at the specified condition cannot be achieved due to an OEM’s test stand cooling capacity limits, and it is often impossible to exactly match the field gas. While a different gas can be used, it must have a k-value (a measure of thermal conductivity) close to the field gas to ensure test and field Mach numbers are equal and the thermodynamic conversion of the work input to the gas produces the same pressure ratio.

Generally, Type 1 test results accurately reflect field performance levels and end users should expect little or no difference between the performance measured during Type 1 testing and those in the real world. The Type 1 test exposes compressors and their auxiliaries to near field conditions. It offers a greater likelihood of uncovering abnormalities in performance (mechanical or aerodynamic) compared to Type 2 tests. Therefore, end users must weigh the higher cost of the Type 1 tests (as much as 10 times) against potential production loss that might arise.

Numerous factors can impact the aerodynamic and mechanical behavior of turbomachinery and the selection process for Type 1 or Type 2 tests. These mostly relate directly or indirectly to the higher pressure and aerodynamic loading experienced on the Type 1 test. Primary among these are deflections or relative movement of parts. As a result, there can be subtle differences in the primary and secondary flow path geometries under Type 1 and Type 2 test conditions.

For example, one of the most common geometric changes that might occur during a Type 1 test (but not under Type 2 test conditions) is bundle deflection due to manufacturing tolerance stack-up. In a typical re-injection compressor, the highest pressure occurs in the last-stage diffusers (for both straight-through and back-to-back arrangements). Thus, forces on the sidewalls of the last-stage diffuser will cause the diffuser walls to move apart. As the last-stage diffuser is also typically the narrowest in a compressor, its behavior is more sensitive to axial deflections.

The amount of deflection depends on the machining tolerances of the bundle components and the fits, as well as material deflections that might occur from pressure forces or thermal effects. Typically, maximum deflections are in the tens of thousandths of inches (or tenths of millimeters) and of little consequence in most compressors.

However, if the design diffuser width is narrow (often the case with high-pressure reinjection compressors), tens of thousandths of inches can be a large percentage of the diffuser width. It is possible for the width to increase sufficiently for diffuser rotating stall to occur, resulting in high levels of subsynchronous radial vibrations. This probably would not be evident during a lower pressure Type 2 test. In one instance, had a Type 1 test not been run at the OEM facility, this exact problem would not have been discovered until the compressor came on-line in the field. The significant warranty implications to the OEM and lost revenue to the end user due to production disruptions would likely dwarf the cost of a Type 1 test. It is advisable, then, that end users, process engineers, and OEMs discuss compressor testing at the OEM’s facility to address aero-mechanical concerns prior to shipping equipment to the site. ■

James Sorokes, is Principal Engineer at Siemens Oil & Gas in Olean, NY. A paper on this topic, “A Comparison of Type 1 versus Type 2 Testing – Recent Experiences Testing A High Pressure, Re-Injection Centrifugal Compressor,” (Sorokes, Kocur, et al) was presented at the 2019 Texas A&M Turbomachinery & Pump Symposium. For more information, visit Siemens.com

High-pressure compressors and how to select the right test

Reality has the nasty habit of undermining well-intentioned theory. If compressor stations would always work at one well-defined, constant operating point, the weather would never change, and units would never have to be shut down. The best thing one can do for any installation would be a single compressor train, without spares.

There are industrial installations where all these assumptions are true. But they are usually not found in oil and gas upstream and midstream applications. This differentiates upstream and midstream applications from most downstream refinery, LNG, and petrochemical plant applications where a fully loaded, single machine is usually the best solution since operational flexibility and load swings are trumped by lower capital costs, higher efficiency and reduced maintenance.

Part of the discussion should incorporate the conceptual differences of different driver types. Drivers used in the oil & gas industry include gas turbines (GTs), steam turbines (STs), electric motors, gas expanders and engines. Availability, part-load efficiency factors or the impact of changing ambient temperatures are different for each of these drivers. This impacts their usefulness for a particular application.

GTs typically have high reliability and availability, and their performance changes with ambient temperature and load. That, and the availability of natural gas as a fuel, makes them an excellent option for upstream and midstream applications. Similarly, STs are widely used in refineries and petrochemical plants because of their reliability, ruggedness, and the availability of centralized steam production.

The demonstrated availability and reliability of GTs and STs is not size-dependent, at least not between 1 MW and 200 MW. More important factors are condition monitoring strategies, logistics strategies and OEM or 3rd party support capabilities.

The argument is often made that larger turbines are more efficient, and less expensive to buy and operate on a costper- power basis. If we compare the efficiency of different turbines, we will find that a 100 kW microturbine is less efficient than a 200 MW unit. However, if we look into smaller scaling ratios this argument does not hold. Specifically, most GTs and STs above 10 MW and below 200 MW have about the same efficiency.

For upstream and midstream, a key consideration is flexibility of installation to adapt to multiple operating conditions. For example, pipeline studies show that the fuel consumption for stations with multiple units is generally lower than for single-unit stations, if the operating conditions fluctuate significantly.

Other studies indicate that outage of a single unit causes a more significant reduction in pipeline throughput than the outage of a unit in a multiple unit compressor station. Several published simulations show the annual pipeline capacity (accounting for established unit availability) tends to be higher for multiple unit installations.

But in most downstream and LNG applications, throughput and operating conditions are relatively steady. For compressor installations, such as refineries and ethylene plants, larger single-unit compression drivers and driven equipment are preferred, mostly because of reduced capital cost, less equipment and installation simplification.

When looking at the cost of operation of pipelines, we find that many compression stations have significant swings in ambient temperatures between day and night and seasonally. These swings are often large enough to shut down one train in a station with multiple units. This improves fuel consumption since a GT at full load has better efficiency than a GT at part load. It also increases station availability as the unused unit can serve as a standby unit. Further, a unit that does not run does not accrue operating hours, reducing maintenance requirements.

Similar schemes have been discussed for single-unit stations by shutting down alternate stations along the pipeline. In general, where pressure losses rise disproportionally if one station is down, pipeline hydraulics rarely allow this. Also, initial design estimates of power demand may have to be revised later. Pipeline hydraulics are sensitive to assumptions on roughness and soil temperatures. In many instances, then, compressor operating conditions do not match predictions once units are in operation.

Additionally, true operating conditions may be different from design conditions. It is relatively easy to construct a scenario that favors an argument for or against big units, but it largely depends on the application. Generally speaking, if a compressor train is sized for a narrow operating range, and temperatures do not affect performance, a single unit will look good. This is often the case when STs or electric motors are used as drivers since their performance is not dependent on ambient temperatures and they require fewer overhauls.

On the other hand, multiple smaller gas turbines are the preferred solutions in applications where a wide operating condition and operational flexibility is critical. There is no simple answer. Bigger is not always better for compressors and their drivers, especially in upstream and midstream applications. The type and appropriate size of the equipment always depends on the application and the operational requirements.

November/December 2019

Siemens Gas & Power bets on innovation

Fast start and peak capacity considerations for combined cycle power plants

How to use your turboexpanders in energy recovery

Bently Nevada's first major condition monitoring platform in 20 years

High-pressure compressors and how to select the right test

Myth: One machinery solution fits every oil & gas application