This column is about nozzles such as the suction nozzles and discharge nozzles connecting piping to compressors, steam turbines, and pumps. In other words, nozzles on turbomachinery casings that connect to the piping. Nozzle loads are loads exerted from piping to the turbomachinery.

Turbomachinery’s capacity to tolerate piping loads is limited. Its effectiveness depends on near-perfect shaft alignment, balanced rotating parts, and proper clearance. Even a small shift in load can challenge this finely tuned condition.

To give you an idea of the significance of relatively low allowable loads and moments specified in turbomachinery codes (such as NEMA and API), the maximum stress in piping when meeting the piping nozzle loads of the turbomachinery is noted for comparison with ordinary piping (those not connected to turbomachinery). For 12-inch (DN300) piping nozzles, the allowable moment corresponds to piping stresses around 15 Mpa. These stress values are even smaller for sensitive machinery such as integrally geared compressors or steam turbines.

For example, for 12-inch (DN300) piping, the allowable moment of a steam turbine corresponds to piping stress of only about 7 Mpa. In comparison, a piping system that does not connect to any machinery can have a thermal stress plus sustained stress of more than 120 Mpa (usually more than 150 Mpa) for most commonly used piping materials.

When size increases, allowable nozzle loads slowly increase. However, the reaction loads of piping increase rapidly with the increase of the piping size. Therefore, it is more challenging to deal with the issue of nozzle loads for large turbomachinery. As a rough indication, piping loads might be assumed to be proportional to the cube of the piping diameter. But in commonly used turbomachinery codes and standards (API, NEMA, etc.), allowable loads are increased less than proportionally to the nozzle diameter. In line with actual numbers, the gap of understanding between piping engineers and turbomachinery manufacturers grows wider as the piping size becomes bigger.

The extremely low allowable nozzle load on large turbomachinery such as steam turbines or integrally geared compressors makes it a challenge to connect them to piping systems. A perfect piping layout is needed combined with a well-planned support and restraint system that includes special components. But this is not always enough. All parties involved, including the designers, engineers, operators, and project managers, should be aware of challenges of piping nozzle loads frequently encountered in the piping systems of delicate turbomachinery applications.

In many cases, expansion joints are prohibited due to maintenance and operational problems. After all, expansion joints can be expensive pieces of equipment and should only be purchased after specific engineering works. They need special care for correct installation, operation and maintenance.

However, when there is no way to make the piping load meet the allowable limit, an expansion joint may be considered. Although an expansion joint is a specialty item requiring special engineering, it is preferable to a system that will not work. Due to high temperature differences and large piping sizes, it may be impossible to provide a piping system that will meet the allowable load, even with loops or other options. This is particularly applicable to some high temperature units such as large steam turbines or extremely low temperature compressors.

The low nozzle loads required by certain turbomachinery applications such as steam turbines or integrally geared compressors, may need expansion joints when piping sizes of 12 inch (DN300) or greater are connected to them.

However, problems have been reported due to improper application or installation of expansion joints. The most direct method of expansion joint installation is to have an anchor to take the entire piping load and to place the expansion joint in between the anchor and the turbomachinery nozzle. This may work well in some cases but not in others. Great care is needed for such an arrangement.

One problem with this arrangement might be the pressure thrust force in the bellows (expansion joint). In order to meet the piping load limitation, the maximum (permitted) internal pressure should be low. Tie-rods can sometimes be added to the expansion joint to deal with this specific issue. However, tie-rods may create other difficulties so they are not popular. ■

Articles

Why some turbomachinery applications need expansion joints

Comprehensive asset management consists of four main pillars: asset life cycle, asset condition management, asset reliability, and asset performance monitoring.

 Under this pillar, the equipment road map must be initiated. The first and most important step is setting a list of equipment. Information for equipment is gathered, such as drawings, data sheets, process diagrams, and input from different disciplines. The second step is the evaluation process, comprised of a criticality assessment. This includes equipment obsolescence and age, previous reliability studies, and maintenance records. The third step defines the action needed for each equipment item, such as replacement, upgrade, or no action is required. The final step is choosing how and when the action will be executed. Is it going to be through capital project or expense?

 The main purpose of this pillar is to monitor critical equipment reliability and interference before failures occur. There are two main programs under asset reliability; reliability technical alert and key performance indicator.

Reliability technical alert is a proactive recommendation that requires immediate attention to guarantee equipment reliability and availability. An example of this comes from the Abqaiq Plants facility in Saudi Arabia, one of the world’s largest oil stabilization plants that includes more than 840 pumps, 30 compressors, 110 steam turbines, and 10 gas turbines. A motor failed at the plant due to internal cable damage, causing electrical grounding. The repair cost of the first motor was $47,424, without including installation, and removal of the motor. During investigation of the cause of the fault, the team noticed an internal cable in contact with an internal support. This contact caused friction, cable insulation deteriorated and led to ground failure. A Reliability Technical Alert was issued to open and inspect the internal condition of sister motors. Signs of similar insulation deterioration were found. The team reinforced the insulation and returned the motor to service.

 Different processes and mechanical parameters are monitored on a monthly basis, such as suction/discharge pressures and temperatures, flow, and bearing vibration and temperature. The normal and allowable range of each parameter is defined to identify any abnormal reading. This allows the reliability engineer to compare values from different months, as well as acting on and providing recommendations before reaching alarm conditions.

Asset performance monitoring: Critical assets are monitored. If a certain item failed more than twice a year, it is included in the bad actor program. Long- and short-term recommendations are tracked until the equipment graduates from the bad actor program. Once graduated, it remains on the list for three months under monitoring to ensure the effectiveness of recommendations to solve and tackle the root cause of the failures.

 This is the most important pillar. It must be understood that one technology cannot do everything. Each technology has a specific field and benefits. All condition monitoring tools require a strong foundation based on establishing a guideline, creating new inspection routes and baselines for each tool, selecting the best reporting mechanism, and establishing a database. Further, all tools must be synchronized with the maintenance management system.

utilize specific tools. This includes lubrication monitoring, thermography inspection, ultrasound, and vibration monitoring.

Lubrication monitoring is one of the fundamental condition monitoring programs as lubrication decreases friction, reduces wear, protects from corrosion, and absorbs heat. According to SKF, over 40% of maintenance costs are related to poor lubrication.

In the Abqaiq Plants oil samples are monitored for 89 equipment items. Physical and chemical property analysis is performed quarterly to look for issues such as bearing particles in the oil. Failure modes of lube oil samples are categorized as follows: oil mixing, degradation, and contamination.

Thermography inspection incorporates a multifunction noncontact application that can be applied for different condition monitoring programs (electrical system faulty electrical connection and overload, mechanical equipment abnormal heat, fluid systems line blockage, and temperature). The Abqaiq plant monitors two hundred items through thermography technology.

For example, thermography was used to detect a mechanical seal cooling blockage for a 500 HP pump. The team noticed low temperature on one side of the mechanical seal flushing line after the cyclone separator. This gave an indication of low flow on the pipe. The pipe was opened for inspection, finding dirt accumulated on the circulation line of the mechanical seal. This would cause a mechanical seal failure due to low flow, which would then lead to mechanical seal face damage. The cost avoidance of this case was $27,000

Ultrasound is used on 400 equipment items on a monthly basis at the Abqaiq Plants. Although it can be used to predict different failures, such as passing valves, steam trap defects, and a lack of lubrication on rotating equipment, it is mainly utilized to monitor the lubrication condition of the rotating equipment, especially bearings that are lubricated with grease. In most cases, ultrasound can determine the lack of lubrication before vibration occurs. A baseline (dB) must be determined for each bearing, and this can be a challenge. In ideal conditions, the dB should be set based on newly installed bearings. If not possible, set it by comparing the dB reading of sister machines with the same species.

Vibration monitoring is used on equipment that lacks an online monitoring system. More than 1,100 equipment items are monitored on a monthly basis at the Abqaiq plant.

Asset management can reduce downtime, unplanned failures, and maintenance costs while improving asset life, prioritizing maintenance activities, and increasing the effectiveness of maintenance management. ■

Assessing asset life cycle, condition, reliability, and performance

The governing and control system of a steam turbine generator controls the entry of steam during starting up to service speed and provides close speed control for synchronization to the electric power system. Once synchronized, the governing system controls the output of the machine. It also provides machine protection, typically using various devices to initiate a trip in emergency conditions. Here, we focus on a system with the turbine generator in normal loaded service.

These systems can include several mechanical linkages and wear can lead to erratic load performance in service. An example was a 200 MW machine that showed unacceptable load variations of ±25 MW. On this machine, the speed governor sleeve movement from zero to full load is 3.6mm. Off-load, 750µm of slack was measured. This explained on-load variations.

Experience has demonstrated the importance of sharp edges on the piston-type spool valves used in these systems. A turbine with erratic governor performance was found to have its governor output spool valve piston edges slightly rounded, as well as having a small nick, presumably from overhaul work. Replacement with the spare resulted in satisfactory performance.

These variations in performance can usually be smoothed out by using an over-riding control (typically called a load limiter). However, this negates the machine’s response to frequency variations. All other machines on the system would take more than their share of the increased load.

The overall speed regulation of the governing system can be found with a load rejection (or load throw-off) test. The machine should settle at a speed corresponding to its regulation. However, this test does not reveal how well the machine responds to frequency variations during normal loaded service. On-load tests should be done to show how incremental regulation is obtained.

In normal loaded operation, the machine’s governing system responds to variations in system frequency, caused by such incidents as another large set tripping off-line. It is important for electric power system stability that each machine responds in the expected manner according to the intended incremental regulation of the machine. Somewhat similar behavior occurs with a domestic motor lawn mower. When more heavily loaded, operating speed drops. The governor responds and opens the throttle so that speed is recovered.

Hysteresis is the phenomenon in which the value of a physical property lags behind changes in the effect causing it; for instance, when magnetic induction lags behind the magnetizing force. A hysteresis test is applicable to any control system with mechanical parts. Starting from a convenient setting, the input control signal is increased in steps in the upwards direction, without reversing the direction of the input. When full range is reached, the input signal is reduced in steps until the minimum setting is reached. The signal is then increased until the original setting is obtained. At each step, the matching output is measured.

A plot of input versus output reveals the presence of hysteresis and allows its extent to be measured, usually as a percentage range. In governing systems, the input signal is usually a control oil pressure which is given from the speed governor.

The steam control valve position is the output and can be obtained with suitably mounted mechanical dial gauges. The valve stem itself may not be accessible and movement of an operating servo may have to be measured instead. Displacement transducers and electronic pressure transducers of suitable ranges can also be used. These enable data to be collected using a datalogger and computer. Another way using an XY plotter is shown in Figure 1. Valve movement is shown on the vertical scale. The horizontal scale is the control oil pressure. Hysteresis here was negligible.

 Figure 1: Hysteresis test on a governor valve[/caption]

This test was performed after maintenance. The up- and down-range plots coincide, as would be expected. Test measurements can be made manually. But on large machines, it requires careful coordination of readings if those taking them are not in sight of each other.

Once synchronised, the speed of a turbine generator varies by very small amounts, according to the system frequency. Most sets have 2-pole generators, and in countries with 50Hz systems, operate at 3000 r/min. System frequency is kept within close bounds such that a mean value of 50Hz results. Variations normally do not exceed ±0.2Hz due to sudden load changes (e.g. because of a generator tripping offline) and the mean frequency is normally recovered within no longer than a second or two.

Also known as droop, steady state speed regulation is the permanent change in speed as a percentage of rated speed, when the loading is reduced to zero without changing the speed/load changer setting. Base-loaded, fossil-fired sets will typically have 4% regulation, while peaking hydro sets can be set at 2% for greater relative response. In today’s market environment, a machine could be set at a higher regulation, say 7%, to reduce its response and minimize output variation. Electronic governing systems can have the setting changed easily online, but mechanical governing systems need linkages to be adjusted.

Incremental regulation (also called incremental droop) is the rate of change of steady state speed with load, at any given speed and load. As this can be hard to visualize as applying over the very small system frequency variations of typically only 0.1Hz in either direction from rated frequency, another way is to express it as the amount of load change per 0.1Hz of speed variation.

All machines showed extremely high values of incremental regulation. An unexpected outcome was that one machine did not respond at all at one load setting. Incorrect original wiring of the control systems was found and rectified.

Another example concerns the testing conducted on a 350 MW machine with mechanical governor and hydraulic servos. With the load limiter control wound out of effect, load was reduced gradually then returned to maximum. Controls were adjusted in the downwards direction until minimum output was reached, then load was raised upwards. Note that hysteresis cannot be identified and isolated unless this procedure is followed. At each step, the load is stabilized while readings are taken.

On this turbine, movement of the speed governor results in movement of a piston-type valve inside a sleeve. The sleeve has drain ports connected to the control oil system, such that changes in relative displacement between the piston and sleeve directly change oil pressure. This pressure, in turn, positions the steam control valves. This relative port displacement can be obtained by speed governor operation, or once machine speed has reached the speed control range when starting up, by the operator moving the speed/load changer (speeder). Once the turbine generator is synchronised, speed is held at system frequency, and speeder movement changes the output of the machine.

During manufacture, the characteristics of the speed governor are tested and the fly-weight springs adjusted to give the design output of axial movement with speed change. This machine should have had a speed regulation of 4%, which corresponds to 5% load per 0.1Hz of speed variation. Speed change of 4% for a 3000r/min machine is 120 r/min, which corresponds to a load from zero to full output. Over this relatively small speed range, the output of the governor is closely proportional to speed.

For this design, a 4% speed change corresponds to a governor sleeve travel of 7.4mm. Using this approach for other selected values of speed regulation, lines of constant speed regulation can be constructed and drawn on axes of speeder travel versus output, as shown on Figure 2.

On test from 250 MW to 360 MW, the speeder travel was measured using a Linear Variable Displacement Transformer (LVDT). Other transducers were connected to measure displacements of other linkages and servo relays in the system, control oil pressures, inlet steam pressure and other variables. A connection was also made to the main output metering. A data logger was used to record the data at ten-second intervals. Earlier in the life of the machine, these tests were done initially and satisfactorily using manual measurements, but errors can be made when reading small distances with a micrometer under the stress of test conditions (hot and noisy).

The measured load values were corrected to the load expected at standard terminal conditions of steam pressure and temperature. With a printout of data at each 10 seconds, sets of readings can be selected at rated values of temperature and pressure, thus avoiding the need for any corrections.

 Figure 2: Load vs Speeder /Load Changer travel on test of a large steam turbine generator. Results are shown with gradients of regulation for 3%, 4% and 5%.[/caption]

The variation in incremental regulation with load can be seen by comparing gradient sections of the test curve with the calculated lines of constant regulation (3, 4 and 5 in Figure 2). Incremental regulation can be seen to be close to the design value of 4%, with departure at higher loads. If desired, it can also be read off at uniform intervals of load and drawn versus load. Hysteresis can be observed, measured and expressed as a percentage range: 0.06Hz maximum is desirable.

Incremental regulation is an important parameter in the performance of the governing system of a steam turbine generator. Simple tests can derive this value on load and reveal any hysteresis in the governing system. Off-load hysteresis tests can be used to examine the relationship between individual components in the system to localize areas requiring maintenance attention. ■

Ray Beebe, OAM MEngSc FIEAust CPEng (ret) worked in fossil-fueled power stations for 28 years in Australia and UK prior to joining academia. He is the author of Steam Turbine Performance and Condition Monitoring. For more information, contact r.beebe@federation.edu.au

Condition monitoring of steam turbine generator governing systems

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Myth: Compressor bearing temperature must be below 200°F

What are the various pros and cons of operating black boxes for compressors?

The main advantage of purpose-built black box controllers is that field-proven logic and algorithms are packaged and protected into one controller. Thus, the risk is greatly minimized of poorly designed logic or algorithms resulting in random plant shutdowns. Also, they provide users with a level of security, where plant personnel cannot routinely access it and accidently cause a system failure and process/plant shutdown. Their main disadvantage is that if the customer desires to modify it in the interest of improving plant processes, they either cannot or are severely limited in doing so.

Why should those with black boxes upgrade?

End-users typically switch from an older black-box based controller to more open control platforms such that they have the capability to modify it in the interest of improving their efficiency, uptime, or plant processes. The latest compressor control systems offer greater visibility into key performance and diagnostic information, allowing users to more accurately understand the health of their compressor package.

Compressor size, complexity, and application are all factors which plant owners use to determine if a compressor packages should be purchased with a purpose-built closed and protected (black box) controller or an open, custom, user-configurable/programmable controller. Smaller simpler compressor packages used for plant air or blower applications are typically purchased as a complete skid or assembly with the black box controls included. However, larger process critical compressors which may require modification during plant commissioning or in the future are typically ordered with open controllers.

End-users are migrating away from the old black-box compressor controllers. This trend is forcing compressor control manufacturers to offer more open architectures and provide the ability for plant engineers to modify and improve control algorithms, and failure fallback logic to optimize plant processes.

Woodward’s new line of controllers, including Vertex, allows customers to view and modify control logic, interface with other plant controllers, and modify and expand hardware input/output signals. Woodward’s Vertex-based Core Software Module (CSM) includes an application program and Graphical User Interface (GUI) program. Users can easily modify both to meet their functionality requirements. Optionally, users can upload the application and GUI programs into one of Woodward’s control platforms (Flex500 or MicroNet). Without modification, it is ready to be configured to operate and protect 1- or 2-stage compressors.

The Vertex controller enables standardization on one compressor control platform across an entire plant. Standardization of controllers and related software can save thousands in spare parts costs and expenses for personnel training. The Vertex controller allows users to configure it to function as a stand-alone control to manage and protect isolated plant compressors or control critical, multi-function compressor packages with more input and output signals and integral network connections to the plant distributed control system (DCS).

How long would an upgrade take from a black box to Vertex? 

Depending on the complexity of the compressor and process, we have customers that were able to physically replace their old compressor control with Vertex in one day then spend the following day adjusting its dynamic response settings to optimize control and process performance. Note that Woodward’s adaptive OptiTune PID controller allows the controller to learn and calculate the system’s dynamic settings ensuring best performance and reducing commissioning times. With more complex compressor controllers which include many input and output signals, multiple functions (anti-surge, decoupling, performance control), and multiple HMIs (human machine interfaces), it may take four or five days to physically replace the old controller. Add two or three days to optimize algorithms.

What percentage of your controls are for new machines versus retrofits? 

This percentage is continually changing. Currently, approximately 60% of Woodard’s compressor controllers are used by compressor OEMs. About 40% are used by OEMs and system integrators to upgrade old obsolete or deactivated control systems.

Compressor owners upgrade the controllers for many reasons. Typically, they wait until the warranty period for their OEM-provided compressor package is past before doing so. Many compressor owners simply wait until the controller is no longer supported, which can be 10 to 15 years. A recent trend shows compressor owners upgrading their controllers sooner to improve plant integration, access more diagnostic information, and or make it simpler to start, stop, and operate.

One of the main trends in the compressor market is users are requiring access to more information within and around the compressor package. They use this information to improve process performance, diagnose compressor package health, and predict future system failures. Plant-wide standardization is another trend we are experiencing, where plant owners desire to standardize on one control platform throughout their plants and compressors. Also, as more plants and systems are connected to the internet and the cloud, a related trend is the requirement for compressor controls to include cybersecurity protection and certification.

As cyber threats to critical infrastructure continue to increase, we believe that cybersecurity certification levels will be required on all controllers being installed with large industrial plants and refineries including compressor controllers.

With more data available, smarter software programs and user service tools will have to evolve to allow both local and remote experts to segment and sort this data based on the specific decision and or analysis being performed. As more remote users gain access to plant information and networks, turbomachinery software will also be required to include multiple layers of user-access security and multiple layers of cyber security. ■

Q&A: Should you use a black box or an open controller?

Centrifugal, Screw and Reciprocating Compressors for Various Operating Conditions

Kobe Steel, also known as Kobelco, manufactures centrifugal, screw and reciprocating compressors. It supplies rotating machinery that serves a wide range of industries and operating conditions. This includes: integrally geared centrifugal compressors for high-pressure applications and large ones for air services; large dry screw compressors and screw compressors for LNG carriers; and reciprocating compressors for LNG carriers.

 Figure 1: Main air compressor for an air separation plant.[/caption]

In recent years, the demand for compressors with greater capacities has been increasing as plants become larger. Kobelco’s integrally geared centrifugal compressors (IGC) cover various applications where large capacities are needed. Typical examples are air separation plants and high-pressure applications such as carbon capture and storage (CCS). Integrally geared centrifugal compressors are gaining in popularity due to their energy-saving features.

The main air compressors used for air separation applications (Figure 1) account for much of the total power used in a plant. As a result, IGCs are increasingly being used for these applications. Recently, the size of plants has increased to improve operational efficiency. Larger IGCs are required with high flow coefficient impellers offering high reliability. In terms of mechanical reliability, it is important to evaluate blade strength against the centrifugal force and the external excitation force when using unshrouded impellers due to the height of the blades.

Large impellers with a high blade height are used for large capacity applications, where vibratory stress of the blades must be correctly assessed and verified (Figure 2). Measurement results reveal that the actual vibratory stress in the various operating points, including the blade resonance and the surge, are at sufficiently low levels when considering the material strength. This confirmed its ability to deal with such stress.

 Figure 2: Kobelco established an evaluation method for dynamic blade stress using optical spot sensors for non-contact blade vibration measurement of the compressor.[/caption]

An integrally geared CO2 centrifugal compressor (2,900 psiG/20 MPaG discharge pressure level) was designed, manufactured and evaluated for fluid dynamic performance and rotor stability. Full-load and full-pressure tests were carried out using real CO2 gas (Figure 3). Compressor fluid dynamic performance was excellent even at high pressure supercritical gas conditions at the high-pressure stages of the compressor. Rotor vibration remained low even at high pressure.

Further tests were conducted. The direct rotor excitation method experimentally investigates rotor stability. With this technique, measurement of actual rotor natural frequencies and the damping ratios (log decrement) during high pressure operating conditions provided more precise results than the conventional casing excitation method.

These results clarified that measured natural frequencies agreed with calculations. Also, the measured damping ratios of the rotor forward modes were higher than the calculated values. The effects of increasing damping methods using squeeze film damper bearings were also investigated during this test. Fluid dynamic characteristics and mechanical reliability were assessed as acceptable including the supercritical gas condition of CO2 gas. Conclusion: The improved reliability and efficiency of IGCs make them an attractive choice for high-pressure and air service applications. And with these compressors saving on space and energy, adoption is increasing.

 Figure 3: Overview of the prototype high-pressure CO2 compressor and test facility.[/caption]

Large-capacity, oil-free screw compressors are widely used in the petrochemical, petroleum refining and gas processing industries. The most popular application for these compressors is in the styrene monomer process in petrochemical plants. Since this application needs high capacity, Model KS63 (rotor diameter of approximately 63 cm) is often adopted.

In response to market demands for even larger machines, Model KS80 (rotor about 80 cm) was developed (Figure 4). Since the rotor is heavy, the casing is split horizontally to provide easy maintenance. Water injection to the compression chamber controls discharge temperature. The rotor and casing are stainless steel.

 Figure 4: Kobelco compressor unit Model KS80[/caption]

To increase capacity, compressor speed is increased. With higher compressor speeds, however, the pulsation level at the discharge side is higher. To reduce pulsation and decrease acoustic energy inside the discharge piping, discharge silencers are usually provided on the suction and discharge nozzles. The pulsation level and its frequency depend on various parameters such as gas composition, pressure, and temperature. Model KS80 compressors can be equipped with silencers designed to meet a variety of requirements.

 Figure 5: Kobelco screw compressor unit for the X-DF engine application[/caption]

Reciprocating and screw compressors are often specified for LNG carriers. Shipping firms facing tightening environmental regulations gravitate to low-speed dual-fuel engines such as the ME-GI and X-DF (Figures 5 & 6).

In the ME-GI system, boil off gas (BOG) of 3.0 – 5.0 t/h generated from the LNG tank is boosted by reciprocating compressors at atmospheric pressure to 30 MPa. It is then supplied to the ME-GI engine for propulsion of LNG carriers. Surplus gas from the intermediate stage (15 MPa) goes to the re-liquefaction system.

 Figure 6: Kobelco reciprocating compressor unit for ME-GI engine application[/caption]

In the X-DF system, BOG generated in the LNG tank is boosted to about 1.5 MPa by a screw compressor. Surplus gas is boosted to 15 MPa by a reciprocating compressor and supplied to the re-liquefaction system. These compressors often include a combined fuel gas control/management system to optimize fuel gas supply to the X-DF engine and re-liquefaction gas to the LNG tank.

Taking into consideration the need for compressors mounted in LNG carriers, a vertical compressor has been developed that is suitable for installation in the limited space on ships. It saves space compared with horizontal compressors.

A re-liquefaction system liquefies excess gas. However, oil contained in the gas can condense inside the heat exchanger in the cooling process, causing a decrease in efficiency. To resolve this issue, a piston ring capable of boosting the pressure to 15 MPa without lubrication was developed. A 30 MPa non-lubricated piston ring has also been completed and will undergo trials. ■

Vendor Spotlight: Kobe Steel

Turbomachinery International recently visited the Commonwealth Chesapeake Power Plant on Virginia’s Eastern Shore. Located at the edge of the town of New Church near the Virginia/Maryland border the plant consists of 7 GE LM6000 aeroderivative gas turbines.

The facility began operation in 2000 with three LM6000s, with four more on order. Each operates in simple cycle mode. A year later, the other four units were added (for a combined plant capacity of 315 MW). In the interim, though, things changed on the regional grid.

The grid operator is the PJM Interconnection regional transmission organization (RTO). PJM originally served Pennsylvania, New Jersey, and Maryland, but now also encompasses all or part of Delaware, Illinois, Indiana, Kentucky, Michigan, North Carolina, Ohio, Tennessee, West Virginia, and District of Columbia. As one of the largest competitive wholesale electricity markets in the world, it boasts 65 million customers and 180 GW of generation capacity.

PJM decided to allow the presence of generators outfitted with clutches that could disconnect from their turbines to enable them to operate as synchronous condensers and provide spinning reserve. The last GE four turbines, therefore, were fitted with clutches from SSS Clutch. These clutches required a slightly larger footprint than the original LM6000s. To allow enough clearance for the clutch between the turbine and generator, the foundation and footing had to be expanded a few feet and shaft couplings had to be added.

As a result, the plant could sell spinning reserve services to PJM. When requested, that generation capacity had to be available online. During this period, PJM pays the plant to have that power on standby. But once the power is required, it must be on the grid within 10 minutes. This enables the RTO to quickly respond to generation or transmission outages elsewhere on its network. Control software is used to bring the turbine rapidly up to near-synchronous speed in order to engage or disengage the turbine. When disengaged, the generator continues to spin (thus, the ancillary service known as spinning reserve). The revenues earned from spinning reserve paid for the clutches within a few years.

 Units 4, 5, 6 and 7 were outfitted with clutches to enable these LM6000s to provide spinning reserve.[/caption]

The ownership of the plant has shifted over the years. The original owner TECO Energy sold it to Tenaska Capital Management who, in turn, sold it to Tyr Energy in 2008. Tyr Energy brought in NAES to operate and maintain the facility. A total of eight operators are involved, split in to four teams to cover all shifts and allow for time off. Four employees remain from the team that began in 2000, one of which is Paul Bernard, Operations & Maintenance (O&M) Manager at the Commonwealth Chesapeake Plant.

“As we are a spinning reserve site, we have to maintain 24-hour coverage,” said Bernard.

He explained that turbines 1, 2, and 3 are direct coupled to the generator and are only used for power generation when required. Units 4 to 7 with clutches are fired up if assigned in the spinning market. He said their mode of operation has changed little over the last twenty years.

The grid on the Eastern Shore’s lower peninsula doesn’t have to serve a large population. However, in the event of grid maintenance, the Commonwealth Chesapeake facility might have to power the entire lower peninsula of Virginia.

As well as the turbines, Bernard and his team look after inlet air chillers, demineralized water and raw water chemical injection skids, and a lube oil storage locker. The facility is currently working with the county to reduce well water usage as part of NOx control. Although it does not utilize potable water onsite, groundwater is always under consideration in the area.

One of the duties of the team is ensuring the supply of liquid fuel for the turbines. Ultra-low sulfur diesel fuel has to be trucked onsite. Dozens of tankers per day would be required if all seven turbines were asked to run simultaneously. These tankers travel two hours south on Route 13 from northern Delaware/Southeast Pennsylvania refineries. As well as being expensive, it opens the door to safety issues and adds to the carbon footprint of the plant. A natural gas pipeline would be a more environmentally sensible solution.

Pre-dating the construction of the plant, there have been discussions about bringing a natural gas pipeline to the area that could provide fuel for the site. Such talks have continued sporadically and progress appeared to have been made recently in bringing a natural gas pipeline down the peninsula into Somerset County, one of the poorest areas of Maryland. A license was recently granted to enable drilling under a river to feed a pipeline further south. If that work moves forward, that could take a pipeline within a few miles of the Commonwealth Chesapeake Power Plant. It seems unlikely that such a pipeline would fail to tie into the plant.

 The Commonwealth Chesapeake Power Plant is maintained by an operations and maintenance team provided by NAES.[/caption]

GE offers a wide variety of upgrades for the LM6000. These include improved combustors, fans, fire protection panels, controls, fast start technology, repowers, asset performance management, and more. With a close eye on maintaining profitability, Commonwealth Chesapeake has not seen the need to make major changes to its seven turbines.

“We’ve kept up with the service bulletins issued by GE, but no major enhancements have been implemented,” said Bernard.

SPRINT (SPray INTercooling) was considered as a way to increase the power output of the LM6000 gas turbine. By cooling the combustion air, greater mass flow travels through the Low Pressure Compressor (LPC) and the High Pressure Compressor (HPC). However, that would have raised water usage. In any case, the existing chillers were deemed sufficient. Similarly, Bernard said that there is no need to add clutches to the other three units. Four, he said, are enough to meet spinning reserve requirements.

Turbine operation is cyclic, largely dependent on regional weather conditions. He said the presence of an approaching cold front, for example, may see anywhere from one to all seven units called upon to provide power.

Maintenance for the site as a whole is minimal. The O&M Manager said the SSS clutches have proven to be robust and are running well with no significant issues experienced over their two decades of operation. External and internal inspections are conducted in the spring and fall.

His advice to others contemplating the spinning reserve market is to retrofit the turbines with clutches to ensure the turbines are constantly available when needed. He said that it is common to receive notice to be available within an hour. Units have to be synchronized in that time. And online in a spinning reserve state with the turbine offline.

“From that moment on, if we have a PJM spin event, we have 10 minutes to get to baseload for turbines,” said Bernard. “If another unit somewhere else trips, they bring us online.”

 The footprint had to be expanded by several feet to allow enough space for the SSS clutch to be positioned between the turbine and the generator.[/caption]

The Commonwealth Chesapeake Power Plant on Virginia’s Eastern Shore may serve as a model on what utilities can do with aging gas turbine plants. With politicians, grid operators, and utilities being subjected to propaganda about the perils of fossil fuels, some are considering shuttering these facilities and replacing them with wind, solar, or battery storage. Those following that course may live to regret any haste in divesting rotating assets.

Older gas turbines have an important role to play in maintaining grid stability and inertia, providing reactive power, and in markets like PJM, providing spinning reserve as an ancillary service. These units can provide standby power where needed, and otherwise can offer the synchronous condensing and spinning reserve services that are likely to be in high demand as a greater percentage of renewable assets come online. ■

 The Commonwealth Chesapeake Power Plant provides standby power to the local grid as well as offering spinning reserve availability to the region.

Spinning Reserve: Commonwealth Chesapeake gives LM6000s double duty

Just how important is software to the field of turbomachinery? This anecdote provides some insight:

In the summer of 1982, software monitoring a Siberian natural gas pipeline commanded the system to run a pressure test at a dangerously high pressure.

“It was a huge explosion. The Air Force thought it was a 3-kiloton blast,” wrote Thomas C. Reed, a former Air Force secretary who served in the National Security Council, in his 2004 memoir, “At the Abyss: An Insider’s History of the Cold War.”

According to Reed, the CIA planted the code in monitoring software it knew Russia would steal. The code ran fine for months until it triggered the blast, which resulted in no deaths. The story remains disputed, especially by former Russian intelligence officials. True or not, it shows that computer technology creates efficiencies valuable enough to steal and how the software can make or break your turbomachinery.

Computer software has come a long way since 1982. It is used to design new parts, monitor the condition of assets, analyze turbomachinery performance, and automate many functions formerly performed by people. The benefits of a digitalized, software-driven world for turbomachinery include the capacity to handle large amounts of data. Now, engineering teams can run larger, more complex simulations using cloud services and pass data seamlessly between teams.

"The benefits of a digitalized, software-driven world for turbomachinery include the capacity to handle large amounts of data."

Design engineers are increasingly using such simulations to bring their designs to market faster and make them greener and more efficient. The design cycle is shortening as technology improves and competition creates little margin for error. For gas turbines, simulation will be key to success of new fuel types such as hydrogen.

The internet is another factor that has risen the profile of software in turbomachinery. Every new product today connects to the internet in one way or another. Like many industries, advantages come to those who can use that data to create better products in the future. Real-time monitoring, for example, helps companies accumulate huge amounts of data that can later be mined to improve current products and improve future designs.

New technologies incorporated into turbomachinery include 3D printing or additive manufacturing (AM), artificial intelligence (AI), machine learning, big data, digitalization, and the internet of things (IoT). Turbomachinery specialists such as Concepts NREC, SoftInWay, Woodward, Siemens Energy, Mitsubishi Power, CFTurbo, Third Wave Systems, Emerson Automation, Open Mind, Howden, Baker Hughes, and GE Gas Power are among the leaders in advancing software and digitalization.

Concepts NREC offers a suite of tools starting from preliminary design through full 3D computational fluid dynamics (CFD), finite element analysis (FEA), and 5-axis machining of turbomachinery. Together, the system is called the Agile Engineering Design System. The company also co-developed a new system called OMNIS with Numeca International. OMNIS is a user interface for all of the company’s software as well as Numeca’s CFD tools so the user can stay in a single environment for all design and analysis tasks.

“Design engineers are considering manufacturing earlier in the process,” said Dr. Peter Weitzman, President, Agile Engineering Software at Concepts NREC. “Many designers work hand in hand with manufacturing counterparts and in some cases are running 5-axis machining software themselves to ensure manufacturability early in the design process.”

Weitzman says that the turbomachinery design community has reached a tipping point where optimization is in widespread use and is a necessary part of being competitive. Thus, optimization tools must work hand in hand with design tools. Further, the optimization structure must be developed by turbomachinery designers for turbomachinery designers.

Simcenter is Siemens’ portfolio of simulation tools covering 3D CFD and FEA, 1D system simulation, and other applications. Engineers use these tools to investigate aspects of turbomachinery performance, from the early design phase to the late stages of product development. These tools enable engineers to investigate many options before any physical testing is carried out.

Simcenter tools work together, and transfer data between software and teams, speeding up collaboration. Simcenter is part of Siemens’ Xcelerator portfolio, enabling other systems to be directly integrated with simulation models.

“The digital twin for predictive maintenance is a reality for gas turbines and generators,” said Erik Munktell, Director of Energy & Turbomachinery at  Siemens Digital Industries Software.

Big data and wireless technologies have changed the way engineers design turbomachinery and the way plants use such software.

“The digital twin for predictive maintenance is a reality for gas turbines and generators,” said Erik Munktell, Director of Energy & Turbomachinery at  Siemens Digital Industries Software. “Data from turbines in operation can be fed back to performance simulations, enabling accurate predictions of component reliability. Engineers can plan for maintenance before component failure, reducing costly unplanned downtime.”

SoftInWay offers the AxSTREAM software platform for design, analysis, and optimization of turbomachinery and related systems. The platform is made up of various modules, covering the complete engineering stack, ranging from thermodynamics to aerodynamics, full 3D structural and CFD simulation, as well as

thermal-fluid systems and rotor dynamics.

“While digital twin technology is improving each day, we feel that true the digital twin is still very much in its infancy,” said Valentine Moroz, Chief Operations Officer, SoftInWay.

SoftInWay software helps engineers create a digital twin of a turbomachine or power plant and can follow its physical counterpart through the complete lifecycle from initial design specification to deployment, operation, monitoring, and servicing in the field.

Lack of data may be the largest obstacle to improving turbomachines and systems. While existing technology such as wireless sensors can help, the digital twin is going to be key in improving machine quality, performance, and operability.

OEMs are often unwilling to give up proprietary design data to end users. This can impact the validity of digital twin. SoftInWay is attempting to build enough technical assumptions into AxSTREAM to generate the data needed to create accurate digital twins.

2020 has seen a major shift in how companies think about turbomachinery design, simulation and analysis. With many engineers working from home, testing physical hardware in person has grown more difficult due to shutdown restrictions and supply chain bottlenecks. In response, companies are placing stronger emphasis on accurate and fast simulation as well as the ability to perform remotely with a geographically distributed team.

While others in the turbomachinery sector focus on monitoring and simulation software, Mitsubishi Power has a focus on the creation of autonomous power plants. The company is creating the building blocks of the world’s first autonomous power plant, T-Point 2, a grid-connected validation facility featuring the M501JAC gas turbine and the Tomoni digital software suite. Tomoni uses algorithms and massive amounts of data to conduct predictive analysis, monitor the plant’s performance, and make improvements.

The digital platform enables analytics and control systems to improve efficiency, generating more electricity with less fuel. Every aspect of plant operation is monitored and optimized.

CFturbo creates software for the conceptual design of axial, mixed-flow, and radial pumps, blowers, fans compressors, and turbines, as well as vaned stators and volutes. It supports reverse engineering, and components made with CFturbo can be exported to rapid prototyping and AM systems.

Company President Ralph Peter Mueller believes the market is growing for turbomachinery design and simulation software and related engineering services. The number of software vendors for turbomachinery design and simulation has risen, and new consulting firms have entered the market.

“We see major trends in massive CFD and FEA-simulation, including automated design exploration and optimization,” said Mueller. “Additionally, additive manufacturing makes much progress, not only for prototyping, but also for production parts. The aerospace industry drives this development. The development of new turbomachinery will be driven more and more by AI technology which can lead to reduced development cost and time.”

Third Wave Systems sells and supports Finite Element Analysis (FEA) software, and AdvantEdge machine modeling. The software helps users understand and capture data that is otherwise impossible to measure in machining tests. It provides data on stress state of a workpiece and can measure various inputs on performance.

AdvantEdge helps to reduce design iterations, simulate more designs, and adds focus to experimental results for faster decision making. As well as speeding time to market, it can help to improve tool performance by pushing tools to their limits, and analyze stress, temperature, and heat flow.

Emerson’s Ovation control platform includes analytics, digital twin, mobile and remote work, and cloud-based services. Emerson specializes in automation and uses modeling from AI and machine learning to identify impending process issues or equipment anomalies to trigger action to avoid downtime or damage. It also supports integrated vibration monitoring, generator excitation control, safety instrumented systems, distributed applications, virtualization, and digital twin embedded simulation.

Most recently, Tennessee Valley Authority (TVA) selected Emerson to modernize and optimize its Magnolia power plant. The Magnolia project is part of TVA’s five-year, $110 million investment to install digital technologies across its power generating fleet. Emerson’s software and technologies will support TVA’s efforts to digitally transform the Mississippi plant through advanced operations, enhanced cybersecurity and digital twin-enabled training.

Open Mind offers CAM and CAD software. The company’s hyperCAD-S software is meant for Numerical Control (NC) programmers conducting CAD-oriented tasks. It also sells hyperMILL, a modular CAM solution for 2.5D, 3D and 5-axis milling, and mill turning and machining operations such as high-speed cutting and high-performance cutting. Applications include milling impellers, blisks, turbine blades, tubes and tire molds.

Individual turbine blades are high-end components that have to meet many different requirements for surface quality and profile accuracy. 5-axis milling processes are commonly used in the production of impellers and blisks.

The machining of impellers and blisks places high demands on CAM software. Standard 5-axis strategies are often insufficient for NC programs to produce these components. Diffusers and casings can also be programmed with the software.

Woodward offers software designed to pair with its custom compressor and steam turbine-based controllers. The software is intended to be a plant’s standard control

platform. Woodward’s Vertex controller is designed for use on industrial-sized axial or centrifugal compressors. Standardization of controllers and related software program is aimed at saving plants in terms of the cost of spare parts and personnel training. Users can configure Vertex to function as a stand-alone control to manage and protect simple isolated plant compressors; or to control multi-function-based compressor packages with more input and output signals and integral network connections to the plant DCS.

“The use of one of these standard application programs, which are already operating and protecting turbomachinery in the field, greatly reduces the risk of a control failure and allows customers to add their own custom site-specific logic and or algorithms,” said Rich Kamphaus, Global Sales Director at Woodward. “Woodward’s new line of controllers, including Vertex, allows customers to easily view and modify control logic, interface with other plant controllers, and modify and expand hardware input/output signals or  program functionality.”

Howden provides condition monitoring and data analysis of equipment performance and processes for insight into the operation of rotating equipment. The Howden Uptime digital platform enables internet-connected products in plants to optimize operational performance. It provides real-time analysis, advice, recommendations, informed decision making, alerts for approaching failures or needed part replacements, and access to equipment documentation.

Howden Remote Assistance uses software known as Vuforia Chalk to combine augmented reality with real-time communications to connect remote product experts to on-site field technicians. The company’s Engineering Suite is a physics-based software package to model, simulate, analyze, and control the performance of process systems. It demonstrates how systems and processes behave in real-time in actual environments.

Howden Ventsim Design software is a 3D ventilation solution. Users create a 3D model of tunnels, shafts, and raises using existing 3D drawings. They can simulate and animate airflow and fan behavior in real-time and analyze mine ventilation within a visual environment.

Ventsim Control is a mine ventilation solution, including data analytics tools. Uses can change mine ventilation to fit working schedules and real-time operations. Fan speed is automatically reduced or increased or switched on and off according to shift changes or planned events such as blasting and position of vehicles and personnel.

Bently Nevada, a Baker Hughes subsidiary, sells condition monitoring sensors and software. Its condition monitoring platform, called System 1, collects high resolution vibration, process, and control system data from a Bentley Nevada device, a Programmable Logic Controller, or from another historian. An alarm on any machine-mapped tag will trigger data capture from all other tags.

The strength of Bently Nevada’s platform is that it is centralized. Plant data is often siloed as it is collected concurrently from handheld devices, manufacturer-installed sensors and third-party sensors. Each monitoring tool collects small pockets of information. System 1 is meant to access all plant data and make plant-wide analyses.

Bently Nevada software can also visualize data collected by sensors. The HMI Builder visually represents an entire plant system and shows operational health.

The company launched a joint venture with Microsoft Azure and an AI company called C3.ai. called BakerHughesC3.ai. The jointly developed BHC3 Production Optimization was also recently released. This AI-based application allows well operators to view real-time production data, better project future production and optimize operations for improved oil and gas production rates.

GE Digital’s Asset Performance Management (APM) software connects disparate data sources and uses analytics to turn data into actionable insights. APM works across all equipment, all OEMs, and all industries, across the plant, and across the fleet. GE says that software is fast advancing in the energy industry equipment sector, especially advanced analytics, machine learning, and digital twin software. ■

The benefits of a digitalized, software-driven world for turbomachinery include the capacity to handle large amounts of data. Now, engineering teams can run larger, more complex simulations using cloud services and pass data seamlessly between teams.

Software expands turbomachinery capabilities

The last ten years witnessed massive shifts in the industry. Back in 2010, I was the fresh-faced, brand new Editor-in-Chief of Turbomachinery International. Coal was king. Renewables were just beginning to have some real traction. Fast forward ten years and natural gas is king – at least in terms of U.S. annual power production. However, no official coronation ever occurred. In fact, the renewable energy camp seems hell bent on deposing gas as soon as possible.

Ten years from now, renewables should be the undisputed champion. But gas won’t be far behind. No matter the dire predictions about gas being gone by 2030, the power grid can’t live without it. Plans to replace it entirely with energy storage, more renewables, and hydrogen have a long way to go to move beyond the wishful thinking stage. Cheap natural gas in the U.S. means it will be hard to dislodge as an important part of the power mix.

The future will be bright if those involved make it so by adapting to changing conditions in the marketplace and finding viable applications for turbines and compressors.

Turning back the clock again to 2010, turbomachinery OEMs were happily manufacturing and marketing the latest gas turbines, combined cycle plants, and oil & gas processing compressors. These days, they are more intent on promoting their green initiatives. Yet the bulk of their sales and service orders are related to natural gas. Hopefully, the fact that the big OEMs have either reorganized or spun off units devoted to the power industry will bring us organizations that find ways to effectively boost turbomachinery sales.

Another big change since 2010 is software. Back then, almost all discussion was about hardware and equipment. Our magazine led the way in introducing more articles on big data, digitalization, cybersecurity, the Internet of Things (IOT), and the latest generation of controllers. These days, these items have firmly moved front and center. That’s why our cover story is about how software is expanding the capabilities of turbomachinery.

The software theme is continued in a contributed article about asset management. Further contributed articles address topics such as steam turbine condition monitoring and the use of expanders for ethylene recovery at an Australian facility. Our show report summarizes the recent virtual Turbomachinery Symposium.

Meanwhile, on a visit to Virginia Beach, I popped into the Commonwealth Chesapeake plant on Virginia’s lower peninsula for a tour and briefing on how they operate as standby power while also providing spinning reserve to the region.

Otherwise, our columnists attack issues such as bearing oil temperature and expansion joints. The Q and A for this issue features a Woodward executive talking about black boxes versus the latest generation controllers. And a new column known as Vendor Spotlight showcases Kobelco laying out its various compressor products.

We began with a mention of how things were 10 years ago. Let’s look ahead to the next ten years. Over that time, the grid is expected to change markedly. The power mix will shift, too, as coal disappears and wind and solar gain further ground. It’s up to our industry to carve out a future that includes turbomachinery applications. Whether they run on natural gas, hydrogen, or something else, the future will be bright if those involved make it so by adapting to changing conditions in the marketplace and finding viable applications for turbines and compressors. ■

It's been quite a decade

 The good old days at the 2019 Turbomachinery & Pump Symposium.[/caption]

The Annual Turbomachinery & Pump Symposium is regarded by many as the premier turbomachinery event. Traditionally set in Houston, TX, the live event was cancelled due to Covid-19. Organizers at Texas A&M’s Turbomachinery Laboratory valiantly battled to provide a virtual version in December of 2020. However, there is nothing like the real thing.

A wealth of sessions made up for the lack of a buzzing exhibition floor. Topics covered included hydrogen compression, seals, gas turbine (GT) performance, combustion, additive manufacturing, turbomachinery in refineries, and operations & maintenance.

Rainer Kurz, Manager of Systems Analysis at Solar Turbines, walked attendees through the performance of the compressor, the combustor and the turbine section during a tutorial session. Also discussed were control concepts for single-shaft and two-shaft machines driving generators, compressors, and pumps.

GT performance characteristics depend on ambient and operating conditions. Consideration must be given to site elevation, ambient temperature, relative humidity, speed of driven equipment, fuel, and load conditions.

January/February 2021