L.A. Turbine provides turboexpander compressors for use in small-scale LNG applications. The knowledge and experience from LNG applications is being applied to new turboexpander designs for clean energy solutions involving hydrogen liquefaction. Chart, our parent company, provides liquefaction solutions. These run all the way from the smallest liquefiers collecting and repurposing bio-methane to large-scale units. Chart’s involvement in natural gas liquefaction enables much collaboration between our companies.


WHAT DOES L.A. TURBINE BRING TO TURBOMACHINERY?


This year marks our 20th anniversary working with turbomachinery equipment. Our product range features a wide range of applications with specific use cases. L.A. Turbine also provides turboexpander-compressors for use in small-scale LNG applications.

CAN YOU SPEAK ON TURBOMACHINERY PROJECTS L.A. TURBINE IS CURRENTLY INVOLVED IN?


L.A. Turbine is currently building a two-stage turboexpander-compressor unit to support Chart’s Nitrogen Refrigeration Cycle Liquefaction System project at an existing U.S. LNG peak shaving facility. This project will see the replacement of the original plant built with modernized liquefaction. The configuration includes two L.A. Turbine L2000 turboexpander-compressors with one expander acting as a warm unit, the other as a cold unit. Theturboexpander is coupled to the compressor as part of the nitrogen loop.

Another is an expansion of the Atlanta Gas & Light LNG facility in Cherokee County, which will double the facility’s liquefaction and storage capacity. The project includes the installation of a second tank, allowing Atlanta Gas Light to store and access gas during peak periods. Construction is currently underway and will be completed in phases over the next three years, including the expansion of their adjacent liquefaction production facility. LNG is growing in areas where inclement weather events are common, such as the Southeastern United States, to alleviate grid instability.


Up until recently, the large-scale LNG market on liquefiers or export/import shore size facilities has seen little to no activity. Large-, mid-, and small-scale opportunities have increased due to macro tailwinds influenced by geopolitical and economic factors. Previous financial hurdles and lengthy approval cycles are reduced, with plant development and construction hurrying. There is significant activity among power and public utilities looking to upgrade aging plants along the coasts especially within mid-Atlantic and Northeastern states. In the last decade, request-for-quote activity amounted to two to three a year with typically one plant awarded annually. Now, it has increased to eight to ten a year with three to four awarded annually. For mid-scale LNG, due to Europe’s need to import LNG, there are opportunities to bring liquefaction capacity to support LNG production, transport, and storage.

Although population growth has slowed, the residential demand for electricity is increasing. Add to this heightened awareness among consumers and demands for safeguards to ensure availability and access to energy sources due to recent blackout and shutdown events. Utilities must ensure energy availability and access to the populations they serve. Investments are needed primarily in upgrades and replacements. Upgrades are often planned in the form of expansion. However, LNG facilities typically endure a lifecycle of 40 to 50 years with proper maintenance, and replacement is ultimately critical to grid sustainability.


Until recently, natural gas was predominantly liquefied in expansive base-load facilities, with an exception being smaller peak shavers that are deployed during periods of high load. However, with modular mid-scale designs, instead of a single, large custom-built facility, total plant capacity can be achieved through a series of replicable modules. Chart refined the small-scale liquefaction model to provide a feasible solution for production and distribution of smaller volumes of LNG, enabling power delivery to off-grid locations. Additionally, this provides an alternative transport fuel for trucks, ships, and locomotives. The ability to move LNG to wherever it is needed is the key. The LNG market for carrier ships, for example, is growing so fast that shipbuilders are unable to fulfill orders. As a result, vessels are being retrofitted to accommodate increased demand. 

Articles

Troy O’Steen, Director of Sales at L.A. Turbine, a provider of turboexpander compressors for LNG, talks about how the market is growing due to increased demand from power and public utilities.

Q&A: Boosting Turbomachinery Utilization in LNG Liquefaction Processes

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

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

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

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

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

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

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


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

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

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

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


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

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

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

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

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

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


Klaus Brun is the Director of R&D at Elliott Group. He is also the past Chair of the Board of Directors of the ASME International Gas Turbine Institute and the IGTI Oil & Gas applications committee.

Rainer Kurz is the Manager of Gas Compressor Engineering at Solar Turbines Incorporated in San Diego, CA. He is an ASME Fellow since 2003 and the past chair of the IGTI Oil and Gas Applications Committee.

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

Myth: Methane Leakage Cannot Be Avoided

Hydraulic systems and hydraulic actuators are robust, reliable, and high performance compared to other types of actuators and systems. This column reveals useful guidelines for hydraulic systems and hydraulic actuators. They offer stiff stroke and operation. Wellconstructed hydraulic actuators are dust tight, and usable in challenging environments.

There are a variety of types and models of hydraulic actuators and systems used in turbomachinery. In hydraulic systems, fluid pressure can be changed to supply different force or torque. This permits more operational flexibility. Linear actuators, hydraulic pistons, and cylinders are popular. Hydraulic linear actuators are usually available as double acting or spring return cylinders.
Hydraulic motors or hydraulic drives are used in different applications. They provide high torque and a wide speed range using a compact motor package. Controls are relatively simple, as a valve handles the flowrate and direction of the hydraulic fluid to the hydraulic motor.

Hydraulic fluids are practically noncompressible inside of hydraulic systems. Therefore, high performance, stiff actuation and operation is attainable. Efficiency of a hydraulic system is relatively low, as heat is generated in normal operation. Initial cost will likely be less than an all electric drive. Therefore, operating expense and maintenance should be factored in when considering the application. There are advantages such as ease with area classifications, smaller sizes, lighter weight, and more which favour hydraulic actuators for specific turbomachinery applications. In these cases, higher load necessitates a hydraulic solution.


There are different control options and valve types for hydraulic system management. However, there are limitations, as the pressurized fluid must be controlled and routed to actuators. Control options therefore may be limited in some hydraulic systems, creating problems related to piping and fluid. There may be environmental concerns in some systems. For instance, the possibility of impacts to piping and tubing, and leakage of hydraulic fluid. Leakage is a common problem afflicting hydraulic systems. This risk requires evaluation and mitigation. Leakage is a common problem afflicting hydraulic systems.

Leakage is a common problem afflicting hydraulic systems. 


Another major concern is dirt, debris, and foreign matter in the hydraulic systems. Components for hydraulic actuators require close machining tolerances to maintain effective seal characteristics. An important component of hydraulic actuators is excellent filtration. If done improperly, frequent maintenance is required. Repairs can be difficult, as any foreign material in
the hydraulic piping or lines can cause damage due to very close tolerances.


Risk management, safety, and reliability are important considerations in hydraulic systems. There is some risk due to tight tolerances in hydraulic actuators or devices. For instance, in the event of fire, the actuators may not operate correctly. The hydraulic fluid used in many hydraulic circuits has a relatively high thermal expansion rate, and the tubing or piping system will have to be protected from possible fire or thermal shocks. Because positive displacement pumps are used in the hydraulic systems of turbomachinery, relief valves are needed. Due to possible thermal expansion, it is necessary to size such a relief valve set to combat thermal over-pressurization.


Incorrectly sized valves, control items, or control valves can result in erratic operation, leading to instability. These include operational problems, vibration, and consequently, wear on devices, valves, and their trims. The force or torque of hydraulic actuators should always be greater than the force required to operate the mechanisms in the turbomachinery. Ample margins are encouraged. When an actuator is fully stroked, it should overcome any breakout force or torque, and internal friction experienced by various sealing components. Undersized hydraulic actuators lock or work sluggishly in these situations.


During commissioning and start-up, it’s likely the hydraulic system contains dirt and debris in the piping, tubing, etc - even after flushing the lines. Flushing might not be effective, permitting damage from foreign matter. Tight tolerances must be factored into risk assessment. Well-planned, multi-stage flushing generates 100% cleanliness of the hydraulic circuit. If there is damage in a hydraulic device due to foreign matter or debris, it’s not enough to simply change the damaged device. The entire hydraulic system should be reevaluated, have its filtration system and cleanliness improved, and reflushed again. There should be a thorough investigation as to where dirt or debris came from, and why the filtration systems or previous flushing was ineffective. Multiple reflushing cycles may be required to ensure a complete clean of the hydraulic system. ■

How to operate and troubleshoot hydraulic systems for turbomachinery

Hydraulic Actuator Tips

Riverhawk is a manufacturing and engineering firm that’s been in the business for three decades. It is both an original equipment manufacturer (OEM) and aftermarket supplier of stud/bolt tensioning tools, diaphragm, and disk pack couplings, coupling accessories, torque management solutions, and installation tools for the couplings used by OEMs and end users. In addition, it provides custom probes, sensors, seismic transducers, and torque meter systems that measure vibration and displacement.

The company a full service one-stop shop for diaphragm couplings. In addition to supplying a new or replacement coupling, it provides all of the installation tooling for the many different shaft end configurations, such as pushers, ring/plug gages, pump kits, fittings, and more. Beyond new couplings and installation tools, a coupling repair service is also available.


“We also offer numerous shaft end accessories and torque management solutions to improve equipment reliability that can be implemented on couplings manufactured by other couplings suppliers,” said Cal Laclair, Business Development Representative at Riverhawk.


Additionally, Riverhawk offers a large catalog of standard tensioners and related hardware. Those working on GE Frame gas or steam turbines will be familiar with its legacy yellow or the latest enhanced orange guarded tensioners that are designed for load coupling bolts.


Riverhawk specializes in the use of hydraulics. The Hydraulic Shrink Disc is an API 617 compliant coupling accessory. It features clamp technology that replaces traditional hub-to-shaft installation methods. The clamp goes on the outside diameter of the hub that slides onto a shaft with a loose fit. Hydraulic pressure is pumped into the clamp which introduces squeezing force, creating an interference fit. Once the desired interference is achieved, the clamp is held mechanically in place with retention screws and the hydraulic fluid is released back into the pump, securing the hub to shaft.


“The Hydraulic Shrink Disc has been our stand-out offering since its inclusion into the fifth edition of API 617 in high-performance coupling applications,” said Laclair. “It provides a good return on investment in terms of cost, time, and safety.”


The Crosshead Nut is another well-known tensioning product exclusively offered by Riverhawk. A modified version of its traditional Hydraulic Tensioned Nut, the Crosshead Nut was designed as an alternative method of tensioning for the cross-head to piston rod connecting joint within a reciprocating compressor. The hydraulic Crosshead Nut is API 618 compliant and has been used by OEMs since 2010.


“It is a significant upgrade over torque jam nuts or multi-bolt jack nuts due to the use of hydraulics instead of torque to achieve uniform and repeatable loading,” said Cal Laclair, Business Development Representative at Riverhawk.


Laclair noted that the company possesses an entire instrumentation line that is available for customers. Back in the 90s, Riverhawk acquired the Indikon Instrumentation Company and shifted manufacturing and distribution to Upstate New York. Instrumentation product offerings include vibration probes and sensors, seismic transducers, and torque meters systems.

“We also offer numerous shaft end accessories and torque management solutions to improve equipment reliability that can be implemented on couplings manufactured by other couplings suppliers,” said Cal Laclair, Riverhawk. 

Crude oil prices have remained high for some time now, with positive implications for certain corners of the turbomachinery industry. According to Laclair, end users are committing to work which was previously put on hold during the COVID-19 pandemic with turnaround times and maintenance schedules extended. “With crude oil prices still on the higher end, we foresee not only an increase of business from rescheduled turnarounds, but an increase in capital spending programs lower crude oil prices would not normally support,” he said.


Overall, the coupling business at Riverhawk is doing well. In addition to inspection, repair, and calibration of tooling, Riverhawk offers global onsite maintenance, training, and supervisory services. Examples include the installation and removal for Frame 7 couplings bolts, taper bored hydraulic hubs, and on-site tooling inspection. Its field reps are ready to travel rapidly to anywhere in the world. More field service support offerings are planned for the near future.


Meanwhile, the company is pushing into new geographies to increase its reach. While mostly operating in the oil and gas, petrochemical, and power generation industries, Riverhawk has dipped its toes into automotive, mining, and agriculture.

Company specializes in hydraulic couplings for turbomachinery

Vendor Spotlight: Riverhawk

ASME Power Test Code (PTC)-10 establishes standards and rules for conducting tests that determine compressor thermodynamic performance at specified operating conditions. The primary goal of thermodynamic performance measurement is to estimate some kind of reference or ideal work input, actual shaft work input, and resulting thermodynamic efficiency. However, such estimation requires measurement of many other quantities. PTC-10 has attempted to provide standardized methods to measure relevant quantities and calculate the performance.


Since the first version of PTC-10 was published in 1935, it has been periodically reviewed and revised to provide updated testing standards as compressor applications have become more diverse. While the 1935 and 1949 versions provided initial guidance for compressor performance measurements, it was the 1965 version that started addressing real gas behavior in performance measurements. An examination of the versions starting from 1965 until now reveals how the code’s compressor performance measurement has evolved over time and may continue to evolve.


1965 – The previous two versions of the code depended mostly on ideal gas laws and generally assumed the test was conducted at the site installation. This revision attempted to address the growing field of compressor applications using non-ideal gases, and to make provisions for the use of multistage compressors with sidestream injection and extraction flows. It established manufacturing shop procedures for testing gases that differ greatly from the specified gas at the compressor installation site. Some of the concerns addressed included: permissible variations in gas properties between the substitute gas and the actual contract gas, the process to obtain reliable thermodynamic properties of the gases, and conversion of test performance values to the guarantee or specified values.


New terms added in the Definitions section include volume ratio, machine Mach number, and machine Reynolds number. The surge limit was added to the list of quantities to be determined by the performance test. Surge and methods to detect it during a test are also described. This code also introduced a new method for classifying tests based on the test gas and the thermodynamic properties at the design point test conditions.


Three test classes were defined. Which test class is conducted depends on whether it was performed at specified gas conditions, or on a substitute gas at different operating conditions. Class I tests are made with the specified gas at the contract speed, inlet pressure, and inlet temperature within the allowable departure (%) limits. Class I tests should be used wherever feasible. Class II and Class III tests are conducted at different operating conditions from the specified and/or other gases, depending on the amount of departure of the gas properties from perfect gas laws. The code defines limits that are referenced to both the specific heat ratio and the compressibility functions. The Class II tests lie within the specified limit values, while the Class III tests fall outside those limits. If these limits are exceeded by either the test or specified gas at any state point along the compression path, then the formulas designated in the code for “real gases” must be used to calculate the performance parameters.


Both Class II and Class III must meet the limits in Table 1 at the design or guarantee operating point. Mechanical losses cannot exceed 10 percent of the total shaft power at the test conditions. This version of the ASME Power Test Code warns that those setting up the test conditions need to verify the accuracy of the gas properties they are using. If the properties are not reliably known, then the test does not comply with the code. Uncertainties in the overall calculations should be evaluated prior to the test to determine if the proposed test will meet the required accuracy. This is the first time the concept of uncertainty analysis was included in the test code. However, the code does not include a method to calculate the uncertainty.


The code also requires that compressors with liquid-cooled diaphragms be tested on the specified gas using Class I tests only. Descriptions of the various compressor test arrangements and their associated flow meters are included (like previous versions of the code), along with several drawings. For the first time, square-edged orifice plates are listed as acceptable flow meters. Reference is made to PTC 19.5 (4-1959) for obtaining their associated flow coefficients or K. Also, several types of flow straighteners are described.


This code revision adopts a new method for calculating polytropic work (head), developed for use with “real” (non-ideal) gases, and introduces the term, polytropic work factor in the head equation. Another new procedure was added for adjusting the tested performance to the specified as a function of the ratio of test to the specified machine Reynolds number.

The method was derived from one established for axial compressors, since at this time, there was little published test data on the Reynolds number effect for centrifugal compressors. Therefore, to be conservative, the efficiency correction was reduced to about half of the axial correction.


The polytropic head is also corrected by the same ratio of specified to test efficiency. It was not uncommon for compressor manufacturers to apply only half of the resultant efficiency correction to the test due to the magnitude of the full correction, and possibly because of some skepticism from the compressor purchaser. The 1965 code also provides examples of Class I, II, and III tests, with detailed calculations showing test values converted to specified conditions.


1997 – Up to 1965, the average time between code revisions was 15 years. Thirty-two years later, the 1997 revision was published and is 195 pages, more than twice the length of the 1965 version, including 100 pages of sample calculations. The code committee reaffirmed this version in 2009, and then again in 2014. In it, the basic list of parameters determined from the performance test has grown to include: quantity of gas delivered, pressure rise produced, head, shaft power required, efficiency, surge point, and choke point.


This edition of the ASME Power Test Code includes more detailed explanations of the procedures and their associated sample calculations. The main changes are: discussion of uncertainty analysis, a new performance correction method based on the Reynolds number, requirements for the treatment of sidestream flows, definition of the allowable departures of machine Mach number and Reynolds number from specified in the form of graphs, revision of the test class or type of test to two (Types 1 and 2), and requirements for multipoint tests.


The code committee wanted to demonstrate how measurement error could propagate to the final calculated results, and that such an analysis before the test can help in choosing instrumentation and methodology. The degree to which uncertainty analysis may be applied to any test depends on the specific test objectives. Based on this, the code makes no firm requirements regarding the use of this analysis and advises addressing this issue prior to the test. Although these calculations can be complex, the 1997 code considers that personal computers now allow for the associated equations and procedures to be programmed and solved rapidly. PTC 19.1 is referenced for providing step-by-step calculation procedures for performing an uncertainty analysis.


By the mid-1970s, both manufacturers and many end users of centrifugal compressor equipment acknowledged that the code correction to efficiency based on the Reynolds number was too large. As a result, the committee adopted a new method based mainly on Wiesner’s work with some simplification for ease of application. However, some end users prefer the ICAAMC method, and have asked that it be applied for their performance tests instead of the recommended one.


Because of the many petrochemical processes requiring multi-section compressors with injection or extraction side streams, the 1997 code tried to provide better guidance for test procedures under these circumstances. It gives clear specifications for the allowable range of variation of sidestream to upstream volume flow rate ratio. These limits are especially important for Type 1 tests at site where only conditions at the compressor flanges (internal data not available) are normally measured. Type 2 tests are commonly performed at the manufacturer’s facility where internal pressure and temperature instruments can be installed. The code only requires the temperature to be measured internally to allow calculation of both the upstream section head and efficiency, and the internal mixed temperature of the downstream section inlet. Internal pressure is not required to be measured and is allowed to be estimated based on the sidestream flange pressure. It also warns to be cognizant during the test of the flow stream temperature differences, which could cause thermal stratification.


For tests requiring multiple points from choke flow to surge flow, the same equivalency rules with respect to volume ratio, Mach number ratio, and Reynolds number ratio apply at each point. Also, the same sidestream to upstream volume flow ratio tolerances apply at off-design points, unless otherwise specified prior to testing. Multipoint tests are now quite common, and typically follow the recommendation of five points to define the necessary performance curves. Purchasers of variable speed compressors often will require additional test points at alternate speeds to define a surge line. Determining choke flow was a new addition, and an explanation is included on how to achieve it on test. However, depending on the compressor and test loop arrangement, a clear definition of choke flow may not be possible.

Thus, it is important that the purchaser define this requirement well in advance of a test. This allows the testing facility to investigate the best means to achieve choke flow or to define the highest flow possible based on the test loop system resistance.


PTC-10 has evolved with both changes in technology and with design and testing of various compressor configurations. It has been almost 25 years since the last version of the code. The limitations of the current version, including its accuracy in evaluating centrifugal compressor thermodynamic performance have been discussed, and the need for an upgrade debated.


Many methods have been proposed for correction of performance prediction based on deviation of Reynolds number from nominal conditions. This includes a unified method for correction of the effects of the Reynolds number, size, and roughness. Such changes in both the performance calculation and correction method should lead to a more accurate compressor performance result and are expected to find a place in future updates of the ASME PTC-10 code. 

Improving compressor performance test accuracy

How PTC-10 Has Evolved

Recently, a series of tests were performed at a Saudi Aramco refinery continuous catalyst regeneration plant (CCR) to examine compressor trip mitigation. Two recycle gas compressors operating in parallel at 50% capacity feed H2 to the CCR. Each compressor is rated for 6 MW, with a maximum continuous speed of 6,200 rpm. They enable hydrogen-rich gas circulation in the reactor circuit. A steam turbine (K-400B) and a variable frequency drive (VFD) electric motor (K-400 A) act as drivers. Each compressor had a different head, so the start-up and shutdown sequences were complicated, and required special consideration. Steam turbine tripping necessitated a total plant shut-down since it could not be restarted while the motor driven compressor was running. K-400B trips lasting longer than four hours and led to total plant shutdown or 60% capacity operation.


Uncovering design limitations of the CCR compressors during commissioning indicated major operational issues for the CCR plant. The current engineer-procure-construct (EPC) design called for a start up of the steam turbine driven compressor (K-0400B) prior to start up of the motor driven compressor feeding H

o the CCR. This wasn’t reflected in any of the process licensor or EPC documents.

During normal unit capacity, K-400B can’t start while J10-K-400A is online, as K-400B can’t develop pressure at idle speed. Upstream pressure of the J-10-E-410 (reactor effluent air cooler) would be almost 2.8 barg while K-400A is running, and lead to K-400B going into surge with the existing piping layout (Figure 1).

Idling mode with 1,500 rpm is required for the compressor turbine KT-0400B prior to increasing the turbine speed to its minimum 4,200 rpm. It cannot be carried out when K-0400A is in operation, since a compressor head with 1,500 rpm is not sufficient to overcome the required discharge pressure developed by the reactor effluent and recycled gas flowing through the effluent condensers. The anti-surge spillback line is taken from the individual compressor discharge and connected upstream to reactor effluent condenser E-0410. With K-0400A running, pressure drop is created through E-0410, E- 0411A/B, and the associated piping. It was too high for K-0400B under idle, and thus, shall be lower than the achievable discharge pressure at 1,500 rpm.

 recycle gas compressor system pressure is governed by the naphtha liquid feed. Reactor circuit pressure drop and recycle gas pressure is largely determined by hydrocarbon flow, rather than compressor speed. This means while K-0400A is running, altering its speed will not influence the reactor circuit pressure drop as much as the liquid feed.


By starting K-400 B first, idling operation can be performed before increasing turbine speed. After reaching minimum turbine speed on compressor-B, compressor-A starts. Afterwards, liquid hydrocarbon is introduced to the reactor. If compressor-B is tripped for any reason, several solutions can alleviate the issue of common tie-in of the compressor’s recycle line to the effluent condenser, mitigating operational limitations.

One route involves continuing turndown operation only with compressor-A, until problems with compressor-B can be resolved. Once compressor-B is fixed, idling operation of the compressor-B turbine can commence. Next, shut down the unit by stopping the feed; then shutdown compressor-A. With intermediate storage tanks, the upstream/downstream units can continue, so impact on the aromatic production should be limited. The upstream naphtha hydro-treating (NHT) will continue to run by sending hydrotreated naphtha to the hydrotreated naphtha storage tank.

Another is to provide a new recycle line from the compressor discharge to flare so that the compressor-B’s discharge can be depressurized to atmosphere. Hydrogen rich gas would be vented and lost to flaring (Figure 2).


A third choice is installing a new recycle line from compressor-B’s discharge to the compressor common suction before the split to the compressors. This ensures compressor-B operates independently from compressor-A during idling, as both compressors have a dedicated loop (Figure 3).


Both the first and second options ended up being excluded. One leads to major process interruption and requires extensive effort to shut down and restart the plant. Number two extrudes high levels of hydrogen rich gas to the atmosphere.

Option three was deemed the best solution. It provided higher operational flexibility, is less harsh on the environment, and only requires minor piping modifications. To eliminate compressor-B surge during turbine idling operation, the discharge pressure of compressor-B must be depressurized and equalized to the suction pressure. This is achieved by providing a new line, bypassing the reactor effluent condensers. With low-speed idling, the temperature rise through compressor-B is marginal, and the required flow rate is small compared to the gas flow rate circulated with compressor-A. Idling operation can be done without temperature escalation at compressor-B’s discharge, as long as the discharge gas is combined with gas from the separator (compressor-A). Here, no additional spillback gas cooler is required (Figure 4).


The differential pressure across J10‐E‐0410, J10‐E‐0411A/B and the associated piping is expected to be approximately 0.2-0.25 bar under 50 % operating load, as per a system hydraulics simulation. According to the performance curve provided by the compressor vendor, the allowable pressure differential between compressor suction and discharge in the idling mode (1,500 rpm) is limited to 0.14 ‐ 0.20 bar. Raising the idle speed was needed to meet differential pressure of 0.2 bar at 50% load. The compressor and steam turbine vendor proposed up to 2,200 rpm for idling compressor-B, which is near the critical speed of the train. This wasn’t possible, as the steam turbine would trip due to high vibration near the critical point. Pressure drop across the loop means pressure upstream the condenser will not be overcome.

Whenever a compressor trips, the plant operation tends to maintain maximum production from the other compressor, which can handle up to 65% of the plant’s capacity. This adds an additional required discharge pressure to be developed by compressor-B, increasing the differential pressure across E-410 and E-411 to approximately 0.3 bar. Compressor surge tends to occur during idling mode when the compressor J10‐K‐0400A is running. Figure 5 shows how this modification adds more operational flexibility, as it allows compressor-B to work independently from the other compressor during idling speed.

Plant management approved Option 3. Moving ahead, more plant flexibility is expected without the need to shut down the plant. Now, the steam turbine compressor will be reset if tripped. Although plant design undergoes several review cycles, important aspects of the design could possess greater limitations for plant operation. Special attention must be paid during dynamic simulation of the compressor anti-surge system and startup scenarios to prevent downtime costs. 

Saudi Armaco is a Saudi Arabian-based petroleum and natural gas company. Its focus is on generating value across the hydrocarbon chain through energy production, chemical refinement, carbon management, and research and development. Visit aramco.com to learn more.

Dynamic simulation of compressor anti-surge system demands special care.

Recycle Gas Compressor Challenges

Companies in the power generation and energy sectors are adapting to recent changes in the landscape. Some segments of the market are taking them on better than others. One success story is that of LNG. Expanding infrastructure for LNG requires increased compressor optimization to handle higher volumes of gas more reliably. Heat recovery steam generators (HRSGs,) too, are in greater demand since they decrease plant energy consumption per ton of LNG produced. Onshore and nearshore LNG applications are adapting to decarbonization initiatives. These and other trends are discussed below to highlight the various ways companies are tackling challenges related to LNG production, transportation, utilization, development, and decarbonization.


Patrice Laporte, Vice President of Sales Compression Americas, Siemens Energy, outlined how the company offers high-speed reciprocating, process reciprocating, and centrifugal compressors. Driven by the shifting energy map of Europe and the Inflation Reduction Act in the United States, the market currently sees significantly increased demand for LNG, CO

 applications, integrally geared compressors are seeing an increased need to modularize the package to reduce lead times. The hydrogen market is also picking up. Generally, the entire gas value chain is driving higher demand.

“Special attention is required for the compressor aerodynamic path design and its integration to the overall LNG plant to meet performance requirements.” said Patrice Laporte, Siemens Energy.

One of the most significant use cases for compressors is in refrigeration. For main refrigerant (MR) applications, compressors increase the pressure of the refrigerant employed to meet process conditions. Depending on the technology employed, normal operating conditions have pressures that can go approximately above 60 bar/870 psi and temperatures as low as -30 °C/-22°F. This machinery operates continuously and is the largest power consumer and operating expense contributor in an LNG plant. Special attention is required for the compressor aerodynamic path design and its integration to the overall LNG plant to meet performance requirements. 

Boil-off-gas (BoG) involves pressurizing vapor byproduct through a compressor that is developed throughout the LNG process and storage units. For this use, LNG vaporizes through expansion and heat input with temperatures as low as -160°C/-256°F. Emissions are one of the top priorities in the conversation of plant operations.

There is debate about using e-LNG compression trains over gas turbines to support emission reductions efforts and decarbonization solutions, particularly for onshore and nearshore LNG. Smaller-scale solutions at 2 MTPA and lower are becoming more prevalent due to faster project duration from the final investment decision (FID) to first LNG production, said Laporte. Further implementation of Voltage Source Inverters (VSI) versus Load Commutated Inverters (LCI) drives helps reduce inter-harmonics. It should be noted that power limitations of large VSI drive systems are becoming less of an issue and will soon be comparable to LCI. Variable Frequency Drive (VFD) systems allow speed control during operation and transient events. Electrical drives are advantageous as they enable independent power and speed manipulation, extending operational capabilities.


Rotoflow has a significant stake with turbomachinery utilization in LNG. The company’s ETAC high-pressure turboexpander line provides refrigeration for air separation and liquefaction facilities around the world. The expander compressor has impeller sizes of 3.5” to 22” and power from 4 to 14,000 kW. However, larger impellers and powers have been adapted. The largest impeller deployed by Rotoflow to date has a diameter greater than 50”, said Bradford Jeanes, Rotoflow Proposal Manager, New Equipment & Product Technology.

Jeanes called attention to the promise of small-scale LNG. Rotoflow’s ETAC-16R high-pressure compander products are used in a variety of LNG facilities, whether land based or floating vessel. One project currently underway is the manufacturing of a large number of high-pressure turboexpanders for an LNG producer in Qatar. Rotoflow’s compander is part of its small-scale LNG (ssLNG) peak-shaving product offering. The ETAC-7R, 8R, and 10R frame models are typically used in peak shaving applications to meet demand spikes. LNG can be seen as the balanced choice between environmental and efficiency considerations, said Jeanes. Demand for clean fuels such as LNG is high right now and for the foreseeable future, he added.

“The largest impeller deployed by Rotoflow to date has a diameter greater than 50”, said Bradford Jeanes, Rotoflow.

Other ways Rotoflow works with LNG are through its ssLNG product line. It offers nitrogen-based refrigeration cycles with an established reference base. Rotoflow is partnering with Air Products’ LNG business, providing new frame solutions (EC-30s and EC-40s) for ssLNG plants. Rotoflow sees LNG as a keystone in developing lower carbon, cleaner energy, without compromising production capabilities.


FS-Elliott offers centrifugal compressor products used in support of LNG production. Its PAP Plus compressor product line is used in LNG and similar applications, according to Dominic Sarachine, Product Manager, Engineered and Air Separation, FS-Elliott. The company’s design philosophy advocates accessibility while meeting specific industry, customer, and site requirements.

The PAP Plus compressor has a completely removable air-end and horizontally split gearcase design. Customization is one of its prime advantages. The product line provides continuous compressed air for instrument air, plant, and process air compressor applications in LNG plants. Compressor capacities start at around 1,000 cfm (35 m3/min) and reach up to 25,000 cfm (700 m3/min). Steady and reliable compressed air is needed to curtail unplanned downtime, said Sarachine. PAP Plus compressors also accommodate site-specific needs, including human factors engineering (HFE) requirements, or hazardous area requirements for operator and plant safety. Operating conditions always need to be considered. Advances in technology mandate continued evaluation of site productivity capabilities.

Sarachine noted that LNG plants tend to reach high operating efficiencies while working at rated conditions. These capabilities depend on practical aerodynamic and mechanical design expertise. LNG today is more focused on equipment performance across wider operating conditions when designing and operating plants, he said. This improved efficiency can contribute to emission reduction. Achieving a broader flow and pressure range while maintaining the greatest efficiency does not necessarily require new impellers, casings, or motors. Simply utilizing the latest advances in control system technology can broaden the operating range of a machine. For example, FS-Elliott’s Regulus Control System offers an energy advisor system to provide operators with recommendations on improving efficiency and a data-driven predictive maintenance module to notify when restorative actions are necessary. Web-based remote monitoring provides a look at compressor health. It’s all part of the bigger conversation on digitalization, paving the way for increasingly accurate and effective measurements.

“LNG is now focused more on equipment efficiency across wider operating conditions when designing and operating plants. This improved efficiency can contribute to emissions reduction,” said Dominic Sarachine, FS-Elliott.

Christian Brotel, Head of Sales Industries, Midstream at MAN Energy Solutions touched on the versatility of LNG in meeting new emission requirements. Some of MAN’s most popular compressor models are horizontally split or barrel-type. These centrifugal compressors are used in chemicals, exploration, production, industrial gases, and more. The models cover a wide range of flow rates along with high discharge pressures. The modular configuration includes predesigned and customizable centrifugal compressor packages.

One special offering of MAN is in Factory LNG. The company’s solution is a small-footprint, modularly scalable liquefaction technology based on the HOFIM emission-free compressor, which allows liquefying natural gas locally for storage, transport, and further use in marine, power, and heat generation applications. Through a fleet of cryogenic transport tanks, LNG can be transported over long distances by truck or train to enable the provision of energy to or from isolated regions. LNG links populations or industries with energy sources across distances where pipeline transport is not available or not feasible. Adaptability is part of why natural gas remains one of the world’s top energy resources.

One way LNG is being produced is in the process of biogas refining. Brotel expects that the market share for biogas will grow. Utilizing Factory LNG technology at large organic waste collection sites, biomethane—or renewable natural gas (RNG)—can be liquefied from biogas. Biogas or biomethane can be used for combined heat and power (CHP) operations or converted into electricity.

“LNG links populations or industries with energy sources across distances where pipeline transport is not available or not feasible”, said Christian Brotel, MAN Energy Solutions.

When considering the flexibility to connect existing gas consumers with new or remote energy sources, including the growing renewables sector, further LNG development seems logical. However, there are other factors at play. A boom will require the adaption and expansion of gas transportation and storage infrastructure. The focus on electrification and emission reduction of compressor equipment means HOFIM and MOPICO hermetically sealed compressors will see more action, according to Brotel.


Mitsubishi Heavy Industries (MHI) Compressor (MCO) was established in 2010 as a dedicated compressor company under MHI. Takashi Niiyama, Group Manager, Project Development Group, Business Development Division at MCO, highlighted the company’s work in energy transition related markets, such as carbon capture and storage (CCS), carbon capture and utilization (CCU), blue and green ammonia, and hydrogen. The technology used evolved within the conventional fields of ammonia and urea, ethylene/propylene, and propane de-hydro plants. MCO produces large compressor casings with consistent rotor stability. Multi-shaft integrally geared compressors are also available in the MCO portfolio, seeing frequent use in CCS and CCU.

MCO designs and manufactures LNG mixed refrigerant (MR) compressors according to licensor requirements. For large LNG liquefaction trains, it offers MR compressor packages utilizing the H-100 gas turbine. This grants variable speed operation in a twin shaft design and simplifies plant configuration and start-up, said Niiyama. Full load string tests are done at their Hiroshima facility before shipment to minimize equipment nonconformities. As for mid-scale & small-scale LNG trains, MCO can offer an e-motor drive solution. MCO supplies auxiliary compression services at LNG facilities, such as EFG, booster, and regen applications.

“New requirements are leading to alternative approaches in operation and execution in the LNG compressor market”, said Takashi Niiyama, MCO.

New requirements bring about alternative approaches in operation and execution in the LNG compressor market, said Niiyama. For example, minimizing site work from a construction stand-point and decarbonization trends. Looking ahead, the number of projects adopting modularization philosophies and/or applying e-motor driver in MR compressor strings is increasing.

Modularization, renewable natural gas, and decarbonization are among key trends spurring growth.