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KODIAK’S STRATEGY
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FROM THE EDITOR
JACK BURKE
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LNG’s next chapter
T
COMMENT
EDITORIAL
he latest International Gas Union (IGU) World LNG Report offers plenty of headline-grabbing statistics. Global LNG trade reached a record 436.98 million tonnes in 2025. Developers sanctioned 68.4 million tonnes per annum of new liquefaction capacity, the strongest year for project approvals since 2019. The U.S. retained its position as the world’s largest LNG exporter, while global liquefaction capacity continues to move to 700 million tonnes by 2030. Those numbers are impressive, but they are not the report’s most important takeaway. The real story is that LNG has entered a new phase of maturity—one in which resilience, flexibility and infrastructure matter as much as production capacity. Only a few years ago, many questioned whether LNG would remain central to the world’s energy mix as countries accelerated decarbonization efforts. Yet geopolitical events have repeatedly reinforced the importance of diversified gas supplies. Europe’s scramble to replace Russian pipeline gas fundamentally reshaped global trade flows. More recently, instability in the Middle East reminded markets how quickly supply disruptions can ripple through the global energy system. Despite those disruptions, the LNG market has continued to function. That’s because today’s industry is far more adaptable than it was a decade ago. In other words, resilience is built one compressor station, one liquefaction train and one regasification terminal at a time. The report also underscores another trend that deserves attention: technology is becoming as important as capacity. Electricdrive liquefaction, digital monitoring, predictive maintenance and carbon capture are no longer niche concepts. They are increasingly becoming part of mainstream LNG project design. That shift creates opportunities not only for equipment manufacturers but also for companies providing controls, automation, condition monitoring and long-term service support. While geopolitical crises may delay projects or redirect cargoes, they have not fundamentally altered the industry’s trajectory. Population growth, urbanization, rising electricity demand, artificial intelligence and data centers continue to support natural gas consumption in many regions. Those structural drivers are unlikely to disappear because of short-term market volatility. If there is one lesson from the past several years, it is that energy security has returned to the forefront of decisionmaking. Governments and customers increasingly value supply diversity, operational flexibility and dependable infrastructure alongside price. As LNG enters its next growth phase, success will depend less on building the largest export terminal and more on creating a resilient global network capable of adapting to whatever challenges come next. Jack Burke Editor | jack.burke@khl.com
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INSIDE
AUGUST-SEPTEMBER 2026
CONTENTS
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INDUSTRY TRENDS
COMPRESSORTECH2 ISSN 1085-2468, is published monthly with combined issues of January/February and August/September by KHL Group Americas LLC, 14269 N 87th, Suite 205, Scottsdale, Arizona, 85260, USA. Periodicals postage is paid at Phoenix, AZ, and additional mailing offices (if applicable).
22 Power in the Permian 48 Compressor launch for growing RNG market 50 Compressor maintenance, digitally empowered 55 The future of LNG
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DEPARTMENTS
3 Editor’s Comment: LNG’s next chapter 6 Industry News: Kodiak’s latest strategy 9 Gas Lines: Gas production outpacing oil in the Permian 10 Company News: Everllence’s big order 13 Monitoring Government: Pipeline regulations 14 Shale Play by Play: EQT sets drilling records 20 Euro Gas Report: Vertical Corridor update 61 Events 62 Tech Corner: Crosshead and pin bearings 77 Cornerstones of Compression: Worthington’s unibloc
INDUSTRY NEWS
KODIAK’S STRATEGY
LUBRICATION
AVOIDING COSTLY ERRORS
CORNERSTONES
WORTHINGTON’S UNIBLOC
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The future of LNG REBUILDING
OUTSIDE
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26 Drivetrain modeling methodology 30 Lessons learned in the field: Venezuela 35 NGL recovery at compressor stations 39 Williams’ latest moves 42 The cost of neglecting compressor lubrication systems 44 Known-source methane capture gains traction
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VOLUME 31 | NUMBER 7
42
A KHL Group publication
50
POWER
IN VENEZUELA
IN THE OILFIELD
DRIVETRAIN
MODELING ADVANCES
55
The future of LNG.
AUGUST-SEPTEMBER 2026 | COMPRESSORTECH2 | 5
INDUSTRY NEWS
A Baker Hughes NovaLT16 turbine. Kodiak and Baker Hughes announced a strategic agreement to produce for up to 1.8 GW of power generation.
IMAGE: BAKER HUGHES
Kodiak, Baker Hughes sign strategic agreement
K
odiak Gas Services and Baker Hughes have entered into a multi-year strategic agreement to deploy gas turbine-based power generation systems supporting the rapid expansion of data centers and other energy infrastructure projects in the United States. The agreement is anchored by an initial equipment award expected to support approximately 1 GW of power generation
capacity by 2030, with a framework that could expand to 1.8 GW over time as demand grows. Kodiak has increasingly targeted behindthe-meter power generation opportunities
A first for Hanwha Power in the U.S.
COMPRESSED NEWS
IMAGE: HANWHA POWER
Hanwha Power has commissioned its first fuel gas compressors in the U.S. with the startup of the 950-MW Trumbull Energy Center combined-cycle gas turbine (CCGT) power plant in Ohio, marking a milestone in the company’s expansion into the North American power generation market. The facility was developed to replace retiring coal-fired generation and will supply electricity into the PJM Interconnection. Hanwha Power supplied three fuel gas compressors for the plant. The units are equipped with variable frequency drives (VFDs) that automatically adjust compressor operation to compensate for seasonal fluctuations in natural gas pipeline pressure, helping maintain a stable fuel supply to the gas turbines and supporting continuous plant operation. Beyond the equipment order, Hanwha The Trumbull Energy Center Combined Cycle Power secured a nine-year long-term Gas Turbine (CCGT) Power Plant in Ohio, U.S. service agreement covering maintenance support and capital spare parts through three major overhaul cycles. The agreement will be supported by the company’s Houston service center through the contract term.
SHELL has taken a final investment decision (FID) to develop a small-scale LNG regasification terminal in The Bahamas, expanding the company’s LNG-to-power portfolio while supporting the Caribbean nation’s transition away from fuel oil and diesel-fired electricity generation. The terminal will supply natural gas for electricity generation, providing an alternative fuel to the diesel and heavy fuel oil that currently dominate the Bahamian power sector. Shell will supply LNG to the facility from its U.S. LNG portfolio, drawing on
6 | COMPRESSORTECH2 | AUGUST-SEPTEMBER 2026
its small-scale LNG experience and regional bunkering network. For Shell, the project strengthens its position in the growing small-scale LNG market, where imported LNG is increasingly being used to replace oil-fired
as electricity demand rises and grid constraints challenge the development of new industrial and digital infrastructure. The initial order includes Baker Hughes’ NovaLT16 and Frame 5 gas turbines, along with BRUSH power generation generators. The equipment is intended for behind-themeter installations in key U.S. markets, providing customers with reliable, rapidly deployable power independent of the electric grid. Kodiak President and CEO Mickey McKee said access to Baker Hughes’ technology, training and support will strengthen the company’s ability to deliver dependable power solutions while supporting its long-term strategy of expanding its energy infrastructure capabilities. Beyond the initial equipment supply, the agreement establishes a framework for closer technical and commercial collaboration between the companies. The arrangement includes commitments related to technical training, spare parts support and a mutual intent to develop a long-term service agreement covering the installed equipment. CT2
generation across island nations and emerging markets lacking pipeline gas infrastructure. NETZSCH PUMPS USA has appointed Brad Schard as sales director for its Oil & Gas business, where he will lead the company’s efforts to expand sales and market share across the U.S. energy sector. Based in Houston, Schard will oversee NETZSCH’s outside and inside sales teams while developing relationships with EPC
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INDUSTRY NEWS
Dover Precision expands testing capabilities with Innovation Lab services
Inside Dover Precision Components’ 12,000-square-foot Innovation Lab in Houston, Texas. IMAGE: DOVER PRECISION COMPONENTS
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IMAGE: XRG
Dover Precision Components has launched advanced product and material testing services aimed at helping original equipment manufacturers (OEMs) and end users accelerate the development and validation of rotating and reciprocating machinery. The new offering leverages the company’s 12,000 sq. ft. Innovation Lab in Houston, Texas, which opened in 2022. The facility now provides external customers with access to engineering services from concept validation through final performance verification under simulated operating conditions. According to the company, the services are intended to help design engineers validate new products, optimize component performance, identify failure mechanisms and shorten development timelines for mission-critical equipment used in compressors, turbines and other rotating machinery. The lab’s capabilities include prototype validation and design optimization, failure mode and root cause analysis, accelerated lifecycle testing, regulatory and compliance testing, and the development of custom test rigs designed to replicate real-world operating conditions.
XRG now holds interests across all five trains currently under construction at the 30 MTPA.
XRG expands stake in Rio Grande LNG with second investment
X
RG has expanded its investment in the Rio Grande LNG export project, acquiring an additional equity stake in Trains 4 and 5 and giving the Abu Dhabi-based energy investment company interests across all five liquefaction trains currently under construction at the Texas facility. The transaction strengthens XRG’s position in the U.S. LNG sector as it continues to build a global natural gas portfolio centered on LNG, pipelines, storage and downstream market access. The company said North America remains a core investment region, citing abundant natural gas resources, growing power demand, industrial expansion and increasing electricity needs driven by artificial intelligence infrastructure.
Operated by NextDecade, Rio Grande LNG is one of the largest LNG export facilities under construction in the United States. The five-train project will have approximately 30 million metric tons per annum (MTPA) of liquefaction capacity. First gas is expected to enter the facility during the second half of 2026, with LNG production scheduled to begin in the first half of 2027. Trains 4 and 5 are expected to add approximately 12 MTPA of LNG production capacity and have secured long-term offtake agreements with investment-grade customers. As part of its initial investment, XRG affiliate ADNOC Trading also signed a 20-year agreement to purchase 1.9 MTPA of LNG from Train 4, providing additional commercial support for the expansion. CT2
firms, OEMs, system integrators and midstream pipeline operators. The company said he will focus on growing demand for its engineered pumping solutions, including the NOTOS multiple-screw pump product line and the NOTOS LACT pipeline booster pump used in liquid pipeline applications.
Industries executive to lead the company as it prepares for a major ownership transition backed by global investors. Patel will assume the role upon completion of the previously announced acquisition of a majority ownership stake in Sempra Infrastructure by a consortium led by KKR. He will also join the company’s board of directors. Most recently, Patel served as president of Standard Industries. Before that, he was CEO of LyondellBasell from 2015 to 2021.
SEMPRA INFRASTRUCTURE has named Bhavesh “Bob” Patel as its incoming chief executive officer, positioning the former LyondellBasell and Standard
AUGUST-SEPTEMBER 2026 | COMPRESSORTECH2 | 7
STRONG PARTNERSHIP TO SERVE CUSTOMERS
WORLDWIDE
Burckhardt Compression AG info@burckhardtcompression.com www.burckhardtcompression.com
KB Delta Inc. info@kbdelta.com www.kbdelta.com
GAS LINES PERMIAN
Rising gas-oil ratios drive Permian production
N
PERMIAN MARKETED NATURAL GAS AND CRUDE OIL PRODUCTION (2021-2025)
atural gas production in the Permian Basin is growing significantly faster than crude oil output as rising gas-oil ratios (GOR) increase the volume of associated gas produced from the region’s wells, according to new analysis from the U.S. Energy Information Administration (EIA). The EIA reported that marketed natural gas production in the Permian increased from 17.2 Bcf/d in 2021 to 27.6 Bcf/d in 2025, a 60% increase. During the same period, crude oil production rose from 4.7 million b/d to 6.6 million b/d, an increase of 39%. The widening gap between oil and gas production growth reflects changing reservoir conditions across the basin. As oil and gas are produced, reservoir pressure declines, allowing natural gas to flow more readily and increasing the amount of gas produced with each barrel of oil. According to the EIA, the Permian’s average gas-oil ratio increased from 3,628 cubic feet per barrel in 2021 to nearly 4,200 cubic feet per barrel in 2025, a 16% increase. The agency expects the trend to
The continued growth in associated gas natural gas production crude oil production production has significant billion cubic feet per day million barrels per day implications. Pipeline operators, gas processors and compression providers have invested heavily in recent years to keep pace with rising gas volumes from the basin, even as oil production remains the primary economic driver for Data Source: U.S. Energy Information Administration, Short-Term Outlook, June 2026 many producers. As gas production continue as the basin matures, resulting in continues to rise, the basin will likely natural gas production growth rates that require additional gathering, processing, outpace crude oil growth. compression and transportation capacity to The EIA estimates that if the Permian’s move increasing volumes of associated gas GOR had remained at its 2021 level, natural to downstream markets. gas production in 2025 would have been The EIA’s analysis suggests that future approximately 23.8 Bcf/d rather than the growth in Permian gas production may actual 27.6 Bcf/d reported. The difference— be driven not only by additional drilling roughly 3.8 Bcf/d—represents additional activity but also by changing reservoir associated gas production generated by characteristics that increase gas output the higher gas-oil ratio. from existing oil-producing areas. CT2
BAKER HUGHES RIG COUNT
US NATURAL GAS STORAGE (Bcf) Source: Baker Hughes
1400 1200 1000 800 600 400 200 0 June-24
June-25 North America
Source: EIA
5000 4500 4000 3500 3000 2500 2000 1500 1000 500 0 January
June-26
HENRY HUB NATURAL GAS SPOT PRICE (US$/MMBtu) $8.00 $7.00 $6.00 $5.00 $4.00 $3.00 $2.00 $1.00 June-24
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June-25
Five-Year High
Five-Year Low
BRENT CRUDE OIL PRICE (US$/Barrel) Source: EIA
$9.00
December 2026
International
June-26
Source: EIA
$130.00 $120.00 $110.00 $100.00 $90.00 $80.00 $70.00 $60.00 $50.00 $40.00 $30.00 June-24
June-25
June-26
AUGUST-SEPTEMBER 2026 | COMPRESSORTECH2 | 9
COMPANY NEWS
Everllence to supply eight compressor trains for Angola FPSO project
E
COMPRESSED NEWS
IMAGE: EVERLLENCE
verllence has secured an order to supply eight compressor trains for a new floating production, storage and offloading (FPSO) vessel being built for offshore Angola, expanding its presence in the offshore gas compression market. The FPSO is being constructed by Yantai CIMC Raffles for Azule Energy, a joint venture between bp and Eni. The project is Yantai CIMC Raffles’ first complete FPSO delivered as an engineering, procurement, construction, installation and commissioning (EPCIC) contractor and reflects the increasing role of Chinese shipyards in
DETECHTION TECHNOLOGIES has rebranded as DETECHTION.AI, signaling a broader focus on integrating artificial intelligence into natural gas compression operations while building on its established monitoring, control and optimization platforms. The company said the new identity reflects its strategy of embedding AI into products and workflows that support oil and gas, energy and industrial operators. Rather than introducing a standalone AI product, Detechtion.AI plans to incorporate AI-driven capabilities across its existing portfolio of compression monitoring, digital twin and fleet optimization solutions. Founded in 1999, the company serves upstream and midstream operators and compression service providers with an integrated platform that combines edge monitoring and control, digital twin optimization, fleet-wide visibility and engineering support.
10 | COMPRESSORTECH2 | AUGUST-SEPTEMBER 2026
Everllence has secured an order to supply eight compressor trains for a new floating production, storage and offloading (FPSO) vessel being built for offshore Angola, expanding its presence in the offshore gas compression market.
SLOAN LUBRICATION SYSTEMS has launched a redesigned homepage aimed at making it easier for customers to find products, services and technical support across a broader range of industrial applications. The company said the updated website better reflects the full scope of its business beyond its traditional focus on lubrication systems, service and replacement parts for reciprocating gas compressors. The new design is intended to help users more quickly identify solutions and access information relevant to their operations. Based in Midland, Texas, Sloan Lubrication Systems provides lubrication equipment,
executing large offshore production projects. The order includes four centrifugal compressor trains and four process gas screw compressor skids for onboard gas processing and export. Everllence said the equipment is designed to meet the reliability and efficiency requirements of offshore production facilities operating in demanding environments. The centrifugal compressor trains will be manufactured at the company’s Zurich, Switzerland, facility and include three electrically driven export gas compressors and one high-pressure compressor. Each train will be equipped with variable frequency drives to provide operational flexibility and optimize process performance. Delivery of the eight compressor trains is scheduled for May 2027. CT2
engineering support, field service and aftermarket parts for reciprocating compressors and other rotating equipment applications. GLOBAL COMPRESSION SERVICES (GCS) has appointed Michael Brooks as chief executive officer, bringing more than three decades of energy industry experience to the compression and gas engine services provider. GCS said Brooks’ background in the gas engine and compressor market positions the company to strengthen its role as a service partner for operators across the industry. According to his professional profile, he has focused on recruiting and developing technical and management talent, implementing customer-focused processes and executing growth strategies designed to increase market share and improve profitability. GCS said Brooks’ expertise will help
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COMPANY NEWS
Report: LNG sees record trade According to the International Gas Union (IGU) 2026 World LNG Report, global LNG trade reached a record 436.98 million tonnes (Mt) in 2025, up 6.3% from the previous year. Liquefaction capacity expanded by 30.1 million tonnes per annum (Mtpa), while developers approved 68.4 Mtpa of new liquefaction projects, the second-highest annual total ever recorded. While geopolitical instability has disrupted short-term markets, the report concludes that LNG's long-term growth trajectory remains intact, with global liquefaction capacity projected to exceed 700 Mt by 2030 under projects already operating or under construction. The U.S. exported 110.74 Mt of LNG during 2025, staying the world's largest LNG exporter. American facilities accounted for 22.3 Mt of the year's 25.7 Mt increase in global LNG exports.
guide the company’s next phase of growth while maintaining its focus on reliability and customer service. RO-FLO COMPRESSORS has appointed Travis Sixel as president, effective July 1, succeeding co-founder Brad Schuler, who is retiring from the role after 19 years. Schuler will remain on the company’s board of directors. Sixel joined Ro-Flo in 2011 as director of engineering and has helped lead the company’s growth, product development and engineering initiatives. Prior to joining Ro-Flo, he held engineering positions with a reciprocating compressor OEM and Caterpillar. Schuler said Sixel has been a key contributor to the company’s evolution from a startup into an established supplier of reciprocating compressor technology. Founded in 2007, Ro-Flo manufactures rotary sliding vane compressors for industrial applications.
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The Northern Lights CO2 receiving terminal in the municipality of Øygarden in western Norway. Burckhardt Compression will supply compression equipment for a liquefied carbon dioxide carrier for the Northern Lights project. IMAGE: NORTHERN LIGHTS
Burckhardt Compression lands compressor order for industrial-scale CO2 carrier
B
urckhardt Compression has secured an order to supply compression equipment for what the company describes as the first industrial-scale liquefied carbon dioxide (LCO2) carrier being deployed as part of the Northern Lights carbon capture and storage (CCS) project. The order represents another step in the development of transportation infrastructure needed to support largescale CCS projects, which increasingly rely on marine transport to move captured carbon dioxide from industrial facilities to permanent storage sites. The vessel will support Northern Lights, the world’s first operational cross-border CO₂ transport and storage network. The project receives captured carbon dioxide from industrial facilities, transports it to an
onshore terminal in Øygarden, Norway, and injects it into permanent storage reservoirs beneath the North Sea. Burckhardt Compression will supply its K Laby compressor technology for the vessel. The company said the reciprocating compressors were selected based on their operational flexibility, energy efficiency and suitability for liquefied gas applications. Andreas Brautsch, president of Burckhardt Compression’s Systems Division, said industrial-scale CO2 shipping is becoming an important enabler for commercial CCS deployment. Burckhardt Compression said the order builds on its experience supplying compressors for liquefied gas applications and reflects growing demand for equipment supporting emerging low-carbon energy and industrial infrastructure. CT2 AUGUST-SEPTEMBER 2026 | COMPRESSORTECH2 | 11
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MONITORING GOVERNMENT
PHMSA seeks to update pipeline repair rule in line with modern technology Inspection improvements cited. By Brian Ford
T
THE AUTHOR
he U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) is proposing substantial changes in federal safety repair requirements for natural gas and hazardous liquids pipelines for the first time in two decades. “Thanks to cutting-edge inspection technology and data, pipeline operators understand their systems better than ever before. PHMSA is modernizing our safety regulations to match this new landscape,” said PHMSA Administrator Paul Roberti in a July 6 announcement. “Prioritizing repairs to target actual threats–rather than sticking to prescriptive, one-size-fits-all timelines– will improve safety and unleash American energy.” The updates will apply data-driven modern engineering concepts for energy operators to determine where and when repairs for things like cracks, dents and corrosion are needed, according to PHMSA. The proposal would enhance worker and community safety and at the same time save money for pipeline operators, according to the federal agency. With the proposed changes, gas transmission pipeline operators are expected to see between US$214.6 million and US$241.7 million in cost savings each year, PHMSA said in its Notice of Proposed Rulemaking (NPRM), while hazardous liquid and carbon dioxide pipeline
BRIAN FORD is editor in chief for Industrial Info Resources, which provides up-to-date project information on a wide range of industries across the globe. He has worked as a reporter and editor for newspapers and other publications since 1979.
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operators can expect to experience annual cost savings of US$148.5 million.
Streamlining timelines PHMSA said the proposal also would streamline compliance timelines into three “clear and consistent” categories across all systems: immediate, near-term (1 year for high-consequence areas), and other conditions. Much has happened over the past 20 years to enable the updates, according to the proposed rulemaking notice. In the early 2000s, PHMSA created integrity management (IM) programs for gas transmission and hazardous liquid pipelines. Both programs included criteria for responding to pipeline anomalies. The requirements—which today apply to 41% of hazardous liquid and less than 18% of gas mileage in high consequence areas (HCAs) and other higher risk locations—used generic depth measurements “that did not account for the specific anomaly or the operating parameters of the pipeline,” PHMSA said. “That approach has forced costly repair of pipelines in good serviceable condition, interrupting service for consumers and disrupting other proactive operational activities.” HCAs are specific locales and areas where a release could have the most significant adverse consequences. HCAs for natural gas transmission pipelines focus on populated areas. Thanks to technological advancements, in-line inspection (ILI) tools can now detect more pipeline anomalies with a higher degree of certainty, even interacting threats and previously unreliably detected threats, according to the rulemaking notice. In 2022, PHMSA amended its gas pipeline response criteria to incorporate some of the more modern, engineering-based concepts. The original response criteria in the integrity management rules from the early 2000s “reflected the limited assessment
technology and evaluation methods available at the time” the agency said in its rulemaking notice. Relying on traditional measurements, the response times for these criteria largely were not based on the anomaly’s remaining safe life. In-line inspection tools analytical methods “were not sufficiently mature to produce highresolution anomaly profiles reliably, to detect and classify interacting threats (such as selective seam weld corrosion and dents with interacting features), or to predict the remaining life of cracks and dents.
Industry players applaud move As a result, the response margins in the original integrity management rules required remediation of anomalies “in advance of what would otherwise be necessary to maintain pipeline integrity in many cases.” PHMSA said it sought public feedback in May 2025 on improving anomaly response requirements for gas and hazardous liquid pipelines. Public response “overwhelmingly favored modernizing these requirements to incorporate a performance-based, engineering-focused approach—one that prioritizes anomalies based on calculated predicted failure pressure, strain, and remaining life rather than one-dimensional thresholds.” Industry organizations such as the American Petroleum Institute and GPA Midstream have lauded the proposed updates. In January, PHMSA published a new rule aimed at modernizing class location regulations for gas transmission lines. The rule will allow natural gas transmission operators to use integrity management practices as an alternative to traditional pressure reductions or pipeline replacements. The alternative allows operators to confirm or restore the maximum allowable operating pressure of certain pipeline segments without replacing pipe or reducing operating pressure. CT2 AUGUST-SEPTEMBER 2026 | COMPRESSORTECH2 | 13
Montana Thrust Belt
Niobrara* Heath**
Cody
BAKKEN*** Williston Basin
Powder River Basin
Big Horn Basin
Gammon
Greater HilliardGreen River BaxterBasin Mancos
Niobrara* Park Basin
Uinta Basin Manning Canyon Piceance Mancos San Joaquin Basin Hermosa Basin Paradox Basin Monterey-Temblor Lewis Monterey, Santa Maria, Ventura, Los Angeles Basins
Appalachian Basin
Michigan Antrim Basin
Mowry
Forest City Basin
Denver Basin
Pierre Raton San Juan Basin Basin Anadarko Basin Palo Duro Bend Basin
Avalon-Bone Spring Barnett-Woodford Marfa Basin
HAYNESVILLE
KinderHawk leads gathering volume growth
Devonian (Ohio) MARCELLUS Utica
Illinois Basin New Albany
Cherokee Platform ExcelloMulky
Chattanooga
FAYETTEVILLE
Arkoma Black Warrior Basin WOODFORD Basin Floyd-Neal Ardmore Basin
Shallowest/youngest
Valley & Ridge Province
Intermediate depth/age
Tuscaloosa Pearsall
EAGLE FORD Western Gulf
James Willis highlights the latest news from the major North American shale plays
MARCELLUS/UTICA
Williams is in advanced talks to acquire Momentum Midstream from EnCap Flatrock Midstream for about $5.5 billion, Bloomberg reported. Momentum operates roughly 4,000 miles of pipeline serving 10 LNG facilities and 26 power plants, including the 250-mile, 2.3 Bcf/d NG3 system to Gillis, Louisiana. The deal would expand Williams’ capacity to move Haynesville gas to Gulf Coast export terminals.
EQT Corporation recently drilled the deepest and longest shale well on land in the continental U.S. The Longwell 9H in Wetzel County, West Virginia, reached a measured depth of 37,610 feet with a 29,070-foot lateral, eclipsing an Expand Energy record set in 2025. EQT said the well was drilled without incident, with 100% of the lateral in target.
14 | COMPRESSORTECH2 | AUGUST-SEPTEMBER 2026
Deepest/oldest
Salt Basin
Basin
Williams nears $5.5B Momentum deal
Mitsubishi’s newly closed $7.5 billion purchase of Aethon Energy’s 2.1 Bcf/d Haynesville position is the third major Japanese acquisition of a private producer in the play since 2023, following Tokyo Gas and JERA. Japanese buyers now control more than 4 Bcfe/d, roughly 30% of Haynesville output.
Basins * Mixed shale & chalk ** Mixed shale & Limestone *** Mixed shale & tight dolostone-siltstone-sandstone STACKED PLAYS
Kinder Morgan reported second-quarter natural gas gathering volumes up 26% year over year, with its Haynesville KinderHawk system posting the largest increase. Companywide gathering averaged 4,637 BBtu/d, against 3,692 a year earlier. The growth follows Kinder Morgan’s start of construction on the $100 million LAHA Header Project near KinderHawk, which adds 750 MMcf/d and comes online in first-quarter 2027.
Japanese firms control 30% of Haynesville
Prospective Plays
Conasuaga
BARNETT HAYNESVILLE- Chattanooga BOSSIER TX-LA-MS Ft. Worth
Permian Basin
Current Plays
EQT sets two U.S. drilling records
earthquakes — separating the Upper and Lower Utica in Tioga County, Pennsylvania. The zero-permeability bed vertically contains fracture growth, preventing interference between intervals. Seneca says the find converts its north-central Pennsylvania position from a single Lower Utica play into a stacked two-zone development with larger inventory.
Ex-Olympus CEO joins Infinity board Seneca finds natural Utica frac barrier Seneca Resources identified a “seismite” layer — sediment deformed by ancient
MIDCONTINENT
NGPL expansion targets Panhandle data centers Natural Gas Pipeline Company of America is developing its Amarillo Expansion to serve rising Texas Panhandle demand, including new data
Infinity Natural Resources appointed Timothy Dugan to its board effective July 13. Dugan led Olympus Energy through its $1.8 billion sale to EQT and previously served as COO of CNX
centers. The roughly $200 million project — Kinder Morgan’s share about $75 million — would add up to 550,000 Dth/d of firm capacity, all subscribed under long-term contract. FERC filing comes in the third quarter, with service targeted for thirdquarter 2028.
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e
SHALE NEWS
PERMIAN
BAKKEN/WILLISTON
Chevron subsidiary Energy Forge One signed a 20-year power purchase agreement with Microsoft for Project Kilby, a co-located gas-fired plant in West Texas (Reeves County) serving a Microsoft data center. The modular 2.67 GW facility will use mostly GE Vernova turbines, with added capacity from Caterpillar’s Solar Turbines. Fueled by Permian gas, Kilby targets FID by year-end and first power in 2028.
Kinder Morgan placed its $165 million Hiland Express Pipeline in service April 29, completing the conversion of the Double H system from crude oil to natural gas liquids and giving Williston Basin producers access to key market hubs.
Chevron, Microsoft plan 2.67 GW project
Hiland Express enters NGL service
Trace to build Apollo gas plant Trace Midstream will build the Apollo Gas Plant, a 250 MMcf/d cryogenic processing facility in Eddy County, New Mexico, plus 36 miles of gathering pipelines and two compressor stations. Backed by long-term contracts, it enters service in Q4 2027. Trace will then operate 200-plus miles of pipeline, 14 compressor stations and more than 125,000 hp of compression.
Producers turn to on-site generation Grid constraints are forcing Permian operators to generate their own power. Mewbourne Oil draws 168 MW from Xcel Energy for its oilfields but needs another 233 MW the utility cannot supply, meeting the gap with more than 300 small natural gas-fired generators. Mewbourne expects to self-supply for at least another decade while awaiting utility capacity.
Marubeni acquires Barnett producer EagleRidge Japan’s Marubeni Corp. has acquired EagleRidge Energy, the Barnett Shale’s third-largest operator, with more than 3,500 wells producing 300 MMcfe/d across 450,000 gross acres in North Texas. Terms were not disclosed. Marubeni plans further North American gas expansion.
Resources and a director of CNX Midstream. The appointment follows Infinity’s Antero Utica acquisition, which added 141 miles of gathering lines and 600 MMcf/d of capacity.
EQT expands Appalachian compression program EQT has six compression projects underway in 2026 and roughly 30 more identified, targeting wellbores carrying about 0.5 Bcf/d annually through 2029. Lower gathering pressure has slowed base decline, running 3% better than plan, and lifted new wells 8% above type curve. Workovers uneconomic under high line pressure now pay out.
SandRidge buys Cherokee bolt-on SandRidge Energy will acquire producing assets and leasehold in the Midcontinent’s Cherokee Play for $65 million cash, its second Cherokee purchase since entering the play in 2024. The bolt-on adds about 7,000 net acres, 3.0 Mboe/d of production at
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Production guidance for 2026 rose to 2,375–2,450 Bcfe.
Greylock opens Potter County field office Greylock Energy opened a field office in Ulysses, Pennsylvania, hosting a June 3 open house for Potter County residents. President and CEO Kyle Mork said the office reflects a long-term commitment to the county. Greylock has invested nearly $1.5 million with PennDOT to reconstruct 3.5 miles of Loucks Mills Road, and has funded scholarships, flood recovery, and local water system equipment.
43% oil, and interests in 21 wells plus eight proven development locations. Closing is expected in the third quarter.
Kolibri raises forecast Kolibri Global Energy has revised its Tishomingo strategy to target additional
Bakken gas to power AI campus Tachyon9 Corporation and Nixxy Inc. signed an offtake agreement with Nidar Infrastructure, parent of India’s Yotta Data Services, anchoring the Nakota AI Data Campus in Williams County, North Dakota. The 620-acre project will run on behindthe-meter, Bakken gas-fired generation, scaling to 1 GW with carbon capture.
WBI upsizes Bakken East pipeline WBI Energy has upsized its proposed Bakken East natural gas pipeline as customer interest ran higher than anticipated, lifting capacity above the original design. The first 134 miles increase from 36-inch to 42-inch diameter and a 162-mile middle segment from 30-inch to 36-inch; the final 57 miles stay 30-inch. The line runs from near Watford City to Mapleton, North Dakota.
FERC approves MS salt-dome storage expansion FERC approved Leaf River Energy Center’s expansion of its New Home Salt Dome facility in Mississippi, adding 19.18 Bcf of working gas capacity to reach 55.18 Bcf. The project includes a new cavern, solution mining of two others, and three gaspowered centrifugal compressors totaling 33,140 hp. EQT contracted 5.46 Bcf of the new capacity.
benches — the False Caney, Upper Caney, T-zone and Sycamore — alongside continued Lower Caney development. A two-mile lateral False Caney well has been added to the 2026 program. Kolibri now forecasts 4,700 to 5,200 boe/d and $56 million to $62 million adjusted EBITDA, assuming $70 oil.
AUGUST-SEPTEMBER 2026 | COMPRESSORTECH2 | 15
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SHALE NEWS
EAGLE FORD
ROCKIES
Tennessee Gas Pipeline applied to FERC on June 5 for its South Texas Enhancement Project, a roughly $90 million effort to add firm transportation to South Texas and Mexico markets and extend shipper paths to new supply. The project includes about 1.7 miles of pipeline, an overpressure protection facility and a new compressor station, targeting second-quarter 2028 service.
Chevron plans the Cord Federal development, 40 wells on 22.8 acres in Adams County, Colo. The tankless design pipes oil, gas and produced water off-site and uses an electric drilling rig, quiet frac fleet and sound walls. No permits have been filed yet, and residents and environmental groups have concerns.
TGP files South Texas project
Chevron plans 40-well pad
Magnolia buys WildFire for $4.06B Magnolia Oil & Gas will acquire WildFire Energy from Warburg Pincus and Kayne Anderson for about $4.06 billion including debt, more than doubling its Giddings acreage. WildFire adds roughly 810,000 net acres and 53,000 boe/d at 70% oil, plus a sand mine and over 500 miles of gas gathering pipelines. Closing is expected late in the third quarter.
completion is targeted for year-end 2026.
Blackstone funds power projects Range slows drilling pace, boosts pad development Range Resources produced 2.30 Bcfe/d in Q2, up 5% year over year. Completion crews cleared the DUC backlog faster than planned, so Range is deferring one pad’s drilling into 2027 and dropping to a single rig and frac crew by Q4. Over half of 2026 activity is on existing pads, cutting cycle times up to 30%.
EQT accelerates MVP Southgate EQT will begin construction on MVP Southgate this year after FERC authorization in June, pulling forward $85 million in capital contributions from 2027. The 31-mile, 30-inch extension will move 550,000 Dth/d from the MVP mainline in Pittsylvania County, VA., to Rockingham County, N.C. Capacity is fully subscribed and construction
Williams signed a $5.34 billion agreement led by Blackstone Credit & Insurance, with Apollo and KKR, funding five behind-themeter power projects in Ohio fueled by Utica and Marcellus gas. Investors take a 49% noncontrolling stake; Williams keeps 51% and operational control. The projects total roughly 1,682 MW, including the 682 MW Neo plant in Licking County. CT2
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EURO GAS REPORT
Anna Kachkova provides information on the latest gas compression news
THE AUTHOR
from Europe ANNA KACHKOVA is an independent oil and gas writer based in Edinburgh, Scotland. She has over 17 years’ experience of covering the energy industry, including five years in Houston, Texas, as NewsBase’s North America editor. Her email address is: aikachkova@gmail.com
EUROPE
Serbia, North Macedonia prepare to join Vertical Corridor Serbia and North Macedonia are preparing to join the Vertical Corridor initiative, which aims to diversify natural gas supplies across Southeastern, Eastern and Central Europe. The corridor transports liquefied natural gas
FRANCE, GERMANY
BarMar green hydrogen pipeline enters FEED stage The H2med consortium has advanced the BarMar green hydrogen pipeline into the frontend engineering and design (FEED) phase, marking another milestone in the development of the European Union’s first cross-border green hydrogen corridor. H2med will link renewable hydrogen production on the Iberian Peninsula with demand centers in Central Europe, particularly France and Germany. The project comprises two cross-border pipelines: CelZa, connecting Celorico da Beira in Portugal with Zamora in Spain, and the offshore BarMar pipeline between Barcelona and Marseille. The consortium includes Spain’s Enagás, France’s NaTran and Teréga, Germany’s OGE and Portugal’s REN-Gasodutos. The FEED phase follows completion of pre-FEED engineering, which confirmed the project’s technical feasibility, established the design basis for the pipeline and compression station, and defined an advanced corridor route incorporating preliminary environmental assessment findings. During FEED, the consortium will finalize the pipeline route and design, complete the compression station layout, prepare permitting documents and develop technical specifications for procurement and construction. The next phase will include awarding FEED engineering contracts and conducting a detailed offshore marine survey. The completed studies will support the consortium’s final investment decision. According to H2med, the 400-km (249-mile) pipeline will operate at pressures of up to 100 bar and include a compressor station rated at up to 60 MW. It is designed to transport up to 2 million metric tons annually, with commercial operation targeted for 2032. 20 | COMPRESSORTECH2 | AUGUST-SEPTEMBER 2026
(LNG) imported through Greece northward into the region. Greece, Bulgaria, Romania and Hungary launched the initiative in 2016 to develop infrastructure enabling bidirectional gas flows. Since Russia’s invasion of Ukraine and the European Union’s decision to phase out Russian gas imports, supply diversification has become a higher priority. Ukraine, Moldova and Slovakia joined the initiative in 2024, with Serbia and North Macedonia now set to follow. Gas transmission system operators (TSOs) from participating countries met in Greece in early July, marking the first participation by North Macedonia’s Nomagas and Serbia’s Transportgas Srbija. Discussions focused on expanding the corridor, available interconnection capacity, infrastructure projects under development and implementation schedules. The TSOs agreed to establish a joint technical and commercial working group to assess regional interconnection capacity and long-term market demand. They also
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EURO GAS REPORT
GERMANY
Gascade begins commissioning Rehden compressor station expansion
ion IMAGE: GASCADE
s
The Rehden compressor station. Gascade began expansion of the station in July.
plan to improve the corridor’s commercial attractiveness by reviewing tariffs and future infrastructure requirements.
SERBIA
Serbia advances gas infrastructure investment program Serbia is preparing to launch the first phase of a major natural gas infrastructure investment program aimed at strengthening and modernizing the country’s transmission network.
Germany’s Gascade began commissioning the expansion of its Rehden compressor station in Diepholz, Lower Saxony, in mid-July. Individual plant components are being brought online sequentially as part of the commissioning process. The project roughly doubles the station’s capacity through the addition of three electric compressors. Once fully operational, the expanded facility will transport larger volumes of natural gas toward Lubmin in northeastern Germany, strengthening security of supply in eastern Germany and neighboring countries in Central and Southeastern Europe. Rehden is one of Germany’s key gas transmission hubs.
The first phase centers on construction of the initial section of the Niš-Velika Plana gas pipeline and is expected to cost more than EUR1 billion ($1.15 billion). The new pipeline will enable Serbia to make fuller use of its cross-border gas interconnections, strengthening its position as a regional gas transit hub while expanding gas access in the country’s southern and eastern regions. Financing and project management were among the key topics discussed
with the World Bank delegation. A working group comprising ministry officials, gas companies and other stakeholders has been established to coordinate project preparation until financing is approved. Discussions also covered creation of a project implementation unit and the institutional support required for execution. Later phases of the investment program will expand Serbia’s gas transmission network, add compressor stations and CT2 increase underground gas storage.
SPECIAL REPORT
POWER IN THE OILFIELD
Power becomes the Permian’s next infrastructure challenge Behind-the-meter generation is evolving into
operations for years while remaining scalable as demand grows.”
permanent oilfield infrastructure, creating new
Beyond temporary power
opportunities. By Jack Burke
T
he Permian Basin’s power challenge is no longer confined to finding temporary electricity for a drilling rig or hydraulic fracturing fleet. Electrification is spreading across nearly every stage of upstream development, turning reliable power into a core element of field infrastructure alongside gathering systems, pipelines and compression. Electric drilling rigs, electric hydraulic fracturing fleets, artificial lift, water handling and electric-drive compression are steadily increasing electricity demand across the basin. ADI Analytics estimates oil and gas operations consumed approximately 3-5 GW of electricity in 2022, with demand expected to reach 10-12 GW by 2032. Total regional demand, including data centers and other industrial users, could eventually exceed 20-25 GW. The result is a fundamental shift in how operators approach power. Rather than viewing onsite generation as a temporary bridge until utility service becomes available, many are beginning to incorporate distributed generation into long-term field development strategies. “It started with everyone thinking of it as a bridge solution, but I increasingly view it
22 | COMPRESSORTECH2 | AUGUST-SEPTEMBER 2026
as a permanent part of the Permian’s energy infrastructure,” said Uday Turaga of ADI Analytics. INNIO is seeing the same transition from the equipment supplier’s perspective. “We increasingly see on-site, decentralized generation being incorporated into longterm field development plans rather than viewed solely as a temporary bridge solution,” the company said in response to COMPRESSORTech2 questions. “Operators need reliable power regardless of utility expansion timelines, and many are designing systems that can support Reliable onsite power is becoming as critical to Permian development as drilling rigs and gathering systems. As operators electrify drilling, hydraulic fracturing and production operations, behind-the-meter generation is increasingly viewed as permanent field infrastructure rather than a temporary bridge solution. IMAGE: INNIO
Grid limitations initially drove much of the demand for onsite generation. Oil and gas development frequently progresses faster than utilities can expand transmission systems and substations, making it impractical for operators to wait years for permanent electrical service. Today, however, the economics have broadened. Dedicated generation offers greater control over reliability, fuel supply, operating costs and resilience, particularly in remote areas where production schedules cannot depend entirely on utility expansion. Turaga believes the long-term model will often combine utility service with behind-the-meter generation. Rather than replacing the grid, onsite power provides redundancy, supports peak electrical demand and allows operators to continue developing areas where utility infrastructure remains unavailable. Commercial activity reflects that transition. Companies including ProPetro, through its ProPWR business, and partnerships involving Diamondback
SPECIAL REPORT
POWER IN THE OILFIELD
“Reciprocating engines generally have advantages in efficiency, modularity and load-following capability. Gas turbines are typically better suited for larger, centralized, continuous-duty applications.” UDAY TURAGA
Energy, Halliburton and VoltaGrid are deploying large natural gas-fueled generation systems capable of supporting electric fracturing fleets and other powerintensive operations.
Matching generation to the load The growth of behind-the-meter generation is also changing how operators select power equipment. According to ADI Analytics, reciprocating gas engines are particularly well suited to distributed generation because they offer modularity, high efficiency and rapid loadfollowing capability. Capacity can be added incrementally as drilling and production expand, making engines attractive for oilfield microgrids and distributed power applications. Gas turbines generally become more competitive where electrical demand is larger, more centralized and relatively
constant, such as major gathering hubs, gas processing plants and production campuses. “Reciprocating engines generally have advantages in efficiency, modularity and load-following capability,” Turaga said. “Gas turbines are typically better suited for larger, centralized, continuous-duty applications.” INNIO said operators are increasingly deploying multiple engine-generator sets rather than relying on a single large unit. The modular approach allows generating capacity to be added or removed as demand changes while improving redundancy. The company also noted that largedisplacement gas engines provide rapid transient response during changing operating conditions. Battery energy storage systems can be integrated to improve overall system performance, while advanced controls and digital asset monitoring simplify operation and provide greater visibility into equipment health across dispersed field assets.
Field gas changes the economics One of the Permian’s greatest advantages is its abundant associated gas production. Rather than purchasing electricity entirely from the grid, operators can use locally produced gas to power drilling rigs, hydraulic fracturing fleets, gathering systems, compression stations and production facilities. According to INNIO, modern reciprocating engines have become increasingly fuel flexible. Waukesha engines can operate on wellhead gas, pipeline gas, stranded gas, flare gas, compressed natural gas, liquefied natural gas and propane, often requiring little or no additional fuel treatment depending on gas quality. That flexibility improves project economics, particularly where gas prices are weak or pipeline takeaway capacity is constrained.
>
SPECIAL REPORT
POWER IN THE OILFIELD
However, Turaga noted that fuel quality and pressure management remain important engineering considerations. Gas composition varies among producing areas and over the life of a field, requiring engineers to evaluate dehydration, contaminant removal, pressure regulation and compression requirements based on individual project conditions.
Compression becomes part of the power system Growing onsite generation does not reduce the importance of compression. Instead, it expands compression’s role. Fuel gas must still be gathered, conditioned and delivered at stable pressure to the generating equipment. As reservoir pressure declines or generating assets are located farther from production, additional compression may be required to maintain reliable fuel delivery. Compression also appears on the demand side of the equation, since many gathering systems themselves are becoming electrically driven. “I think the implications for compression are significant and generally positive,” Turaga said. “More onsite generation creates additional demand for fuel-gas gathering, treatment and compression infrastructure.” INNIO likewise emphasized that reliability is paramount in Permian operating conditions. High ambient temperatures, dust, remote locations and continuous-duty operation are increasing the importance of redundancy, remote monitoring and predictive maintenance. Digital monitoring systems are helping operators optimize maintenance planning while maximizing equipment uptime across geographically dispersed assets.
Compression providers move into power The similarities between contract compression and power-as-a-service are encouraging some compression companies to expand into distributed generation. Turaga believes many already possess the operational capabilities needed for the transition. Contract compression providers understand how to deploy large engine-driven equipment quickly, maintain 24 | COMPRESSORTECH2 | AUGUST-SEPTEMBER 2026
rotating machinery under long-term service agreements and support customers whose primary objective is uptime rather than equipment ownership. “The core competencies of contract compression companies are really their ability to move equipment from point A to point B on demand and to be able to set up and deploy pretty quickly,” Turaga said. The transition nevertheless requires additional expertise in generators, switchgear, electrical protection systems and microgrid controls, creating opportunities for partnerships between traditional compression companies and power system specialists.
Data centers add another source of demand Oil and gas operators are no longer the only customers competing for gas turbines, reciprocating engines, generators and electrical equipment. Data center developers are rapidly increasing demand for dedicated natural gas-fired generation, often pursuing the same equipment suppliers serving the upstream energy sector. Turaga believes hyperscale operators possess considerable financial advantages that could tighten equipment availability and extend lead times for engines, turbines, generators and switchgear. Many future facilities are expected to combine utility service with behind-the-meter generation, further increasing demand for natural gas infrastructure.
Infrastructure execution becomes the challenge Despite strong demand, Turaga sees execution rather than market fundamentals
Modular engine-generator packages allow operators to add generating capacity as field development expands while providing the redundancy and flexibility needed for remote oilfield operations. IMAGE: INNIO
as the industry’s primary constraint. Lead times remain lengthy for engines, turbines, generators and electrical equipment. Skilled labor remains limited, while permitting requirements and fuel-gas infrastructure can delay projects. At the same time, emissions requirements are becoming increasingly important during project planning. INNIO said operators are seeking solutions that satisfy permitting requirements while maintaining operational flexibility. The company noted that utilizing available natural gas together with emissions-control technologies can help support both operational and environmental objectives. The larger change, however, extends beyond any single piece of equipment. Power is becoming another permanent layer of oilfield infrastructure. As operators electrify drilling, fracturing, artificial lift, water handling and compression, successful projects will increasingly depend on integrating power generation, fuel-gas treatment, compression, controls and digital monitoring into a single operating system. For the compression industry, that evolution represents an opportunity that reaches well beyond supplying another compressor package. Compressors are becoming an essential link between natural gas production and power generation, helping transform associated gas into reliable electricity that supports the next generation of Permian development. CT2 www.compressortech2.com
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TORSIONAL ANALYSIS JOHN CRANE
Rethinking torsional stiffness fo methodology.
measured drivetrain behavior. According to John Crane, the improved drivetrain models can reduce commissioning risk, improve reliability and help identify potential resonance issues before equipment enters service.
By Jack Burke
Why traditional models fall short
John Crane’s new dynamic coupling
Torsional analysis is a critical part of designing rotating equipment trains. Engineers evaluate how motors, turbines, gearboxes, couplings and driven equipment behave together to ensure the system’s natural frequencies do not coincide with operating speeds. Historically, coupling manufacturers have supplied a single torsional stiffness value for use in these analyses. The problem, Pennington explained, is that couplings do not actually behave that way. “We stumbled upon a nonlinear response,” he said. “That led us to believe we should be giving multiple torsional
F
26 | COMPRESSORTECH2 | AUGUST-SEPTEMBER 2026
John Crane said its new dynamic coupling methodology improves drivetrain modeling by accounting for torquedependent stiffness, helping OEMs reduce commissioning risk and improve reliability.
IMAGE: JOHN CRANE
or decades, drivetrain torsional analysis has relied on a fundamental assumption: the torsional stiffness of a coupling is a fixed value. That assumption has served the rotating equipment industry reasonably well, but as compressor trains become increasingly sophisticated—particularly with the widespread adoption of variable frequency drives (VFDs), electric motors and wider operating envelopes—it has also become one of the industry’s biggest limitations. According to Steve Pennington, Global Engineering Coupling Manager at John Crane, the gap between modeled performance and actual operating behavior has become increasingly apparent. “We were seeing an increase in questions around torsional stiffness based on variable frequency drives and the accuracy of the calculations,” Pennington said. “Traditionally, ourselves and the whole coupling community supplied one torsional stiffness value, but we had a few applications where the value wasn’t correlating as accurately as we would have liked in the field.” That realization prompted a threeyear research effort that has resulted in what John Crane describes as an industry-first validated methodology for drivetrain analysis. Rather than treating coupling stiffness as constant, the new approach models stiffness as a dynamic characteristic that changes with torque and operating conditions. The methodology has been validated through analytical modeling, laboratory testing and multiple field installations, significantly improving the correlation between predicted and
stiffness values instead of just one.” Further testing uncovered an even more significant finding. “When we saw very small changes in torque, the coupling started using its hysteresis behavior to damp out the system,” he said. “That meant we could accurately predict torsional stiffness for a particular torque value, allowing customers to operate much closer to natural frequencies while using the coupling’s own damping capability.” In practical terms, Pennington said, the coupling’s stiffness changes throughout its operating range. Instead of behaving like a rigid spring with one constant characteristic, it responds differently during startup, steady-state operation and changing load conditions. John Crane now defines these regions separately, distinguishing between an initial “dynamic stiffness” region and the traditional “static stiffness” values used during normal operation.
www.compressortech2.com
TORSIONAL ANALYSIS
JOHN CRANE
ss for the variable-speed era Variable-speed systems raise the stakes Pennington said the growing use of variable frequency drives throughout the natural gas industry has increased the need for more accurate drivetrain analysis because compressor trains now operate across a much wider range of speeds and torque conditions. Unlike fixed-speed compressor trains, variable-speed systems operate across a broad range of speeds and torque conditions. That flexibility improves efficiency and process control, but it also increases the likelihood that equipment will pass near torsional natural frequencies during startup, shutdown or load changes. “The more complex drives—the lowspeed, high-speed coupling applications and multiple drivetrains—are where we can really benefit,” Pennington said. “We can now pinpoint torsional stiffness for a particular torque over the operating range.”
“If you want to improve efficiency, change the drivetrain or operate in a different range, we now have more knowledge about the torsional stiffness and can work much more accurately.” STEVE PENNINGTON
www.compressortech2.com
Rather than forcing engineers to work with an averaged stiffness value, Pennington said the methodology provides multiple operating points, enabling much more representative system models. “We can make the torsional analysis super accurate,” he said. “The only limitation now is how much information today’s analysis software can practically use.”
From laboratory to field John Crane did not introduce the methodology until it had been validated in actual operating equipment. Development began with conventional static testing before engineers designed a unique dynamic test rig capable of measuring torsional stiffness while the coupling was rotating. “We came up with a very unique solution to measuring torsional stiffness dynamically,” Pennington said. “Using optical measurements on our dynamic test rig, we were able to measure torsional stiffness dynamically, which is quite unique.” The company then compared those results against analytical models before validating the approach in operating machinery. “We tested statically and dynamically, got correlation with finite element analysis and then, more importantly, extremely accurate correlation with what went on site,” Pennington said. “We’ve had strain gauges on site measuring the torsional forces, and we’re within a couple of percent of where we predicted we’d be. For drivetrain analysis, that’s exceptionally close.” To date, the methodology has been successfully deployed on four customer applications. In one case, a drivetrain repeatedly encountered a torsional critical speed during operation. “Previously, we were moving into a first natural critical and had to stop the machinery,” Pennington said. “We changed the parameters using the new methodology,
and now the equipment operates at exactly the same speed without hitting the critical frequency.”
Reducing commissioning surprises For compressor packagers and EPC contractors, commissioning is often where deficiencies in drivetrain modeling become painfully obvious. Unexpected resonance problems discovered during startup can delay projects, require redesigned couplings or force operating restrictions until permanent solutions are implemented. Pennington believes improving prediction accuracy can significantly reduce those risks. “By the time it gets to commissioning, we’re supplying something we know is going to work,” he said. “In the past we’ve had situations where we had to go back and manufacture different couplings to change the torsional characteristics. Now we’ve already proven the design before commissioning.” Pennington said that confidence is particularly valuable on large LNG, pipeline compression and power generation projects where delays can have substantial financial consequences. He also said the methodology improves collaboration among OEMs by providing more representative drivetrain information during the design phase, helping reduce integration issues before equipment reaches the field.
What about existing equipment? One of the first questions John Crane received after introducing the methodology concerned legacy equipment. If engineers have been using a simplified stiffness model for years, does that mean existing compressor trains are at risk? According to Pennington, the answer is no. “The existing fleet is fine,” he said. “We’re not changing anything that’s already there. We’re enhancing the understanding and providing greater accuracy.” AUGUST-SEPTEMBER 2026 | COMPRESSORTECH2 | 27
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TORSIONAL ANALYSIS JOHN CRANE
Instead, he said, the additional information becomes most valuable when operators upgrade equipment, retrofit VFDs or modify operating conditions. “If you want to improve efficiency, change the drivetrain or operate in a different range, we now have more knowledge about the torsional stiffness and can work much more accurately,” he said. Pennington said retrofit projects can particularly benefit from the methodology because historical drivetrain information is often incomplete.
“The challenge now is that we’re almost overloading OEMs with information because today’s software can’t always use all of it.” Even so, Pennington expects analysis tools to evolve alongside the methodology. Looking ahead, he said artificial intelligence could eventually help engineers interpret increasingly complex drivetrain data, although the immediate focus remains on further refining the underlying models. “We’ve got another year of testing planned,” he said. “There are another three parameters we want to review. It’s all about increasing the accuracy even further.”
More data—and more opportunities
A shift in drivetrain engineering
The methodology is currently being rolled out to additional OEMs following successful implementation with an initial customer. Not surprisingly, the increased accuracy also creates a new challenge: information overload. “We actually have four different points on the torque curve,” Pennington said.
Looking ahead, Pennington believes increasingly sophisticated drivetrain analysis will become more important as compressor packages incorporate variable-speed motors, electric drives and more advanced control strategies. He said better correlation between modeled and actual operating behavior can help OEMs
and operators reduce commissioning issues while improving long-term reliability. Pennington also said the work challenges one of the rotating equipment industry’s longstanding assumptions— that coupling torsional stiffness can be represented by a single constant value. According to him, incorporating multiple operating points into drivetrain models provides a more representative picture of how couplings behave under real operating conditions. John Crane said the methodology is intended to provide engineers with more accurate drivetrain information during the design process, particularly for new installations, equipment upgrades and variable-speed applications. The company said the objective is to reduce commissioning surprises, improve system performance and give OEMs and end users greater confidence that modeled drivetrain behavior will closely match actual operating conditions. CT2
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VENEZUELA’S LESSONS ELLIOTT TURBO
Restarting neglected infrastructure
Restoring aging turbomachinery can require extensive inspection and repair before equipment is returned to service.
Venezuela’s recovery highlights lessons for aging turbomachinery fleets worldwide. By Jack Burke
A
s Venezuela works to revive an oil and gas industry that has endured decades of underinvestment, operators are confronting a reality familiar to many owners of aging compression and processing assets: getting production back online is often less about drilling new wells than restoring the machinery already in place. According to Dr. Klaus Brun, vice president of products and technology at Ebara Elliott Energy (EEE), years of deferred maintenance have left many facilities struggling with declining reliability, obsolete systems, missing spare parts and workforce shortages. “Venezuela has had about 30 years of underinvestment in machinery,” Brun said. “That has resulted in plunging production, low machinery reliability and many unused or abandoned machines.” EEE, headquartered in Jeannette, Pennsylvania, has supplied compressors, steam turbines, pumps and expanders to Venezuela’s energy sector for decades and estimates that between 700 and 800 of its machines remain in service throughout the country. Determining how many remain operational, however, requires a painstaking machine-by-machine evaluation.
Inspection comes first Brun said operators often underestimate the complexity of restoring long-idled equipment. 30 | COMPRESSORTECH2 | AUGUST-SEPTEMBER 2026
Detailed inspection of turbomachinery and supporting systems is critical when evaluating equipment for continued service or modernization.
The first step is a comprehensive inspection that includes visual assessments, vibration testing, non-destructive examination, spare-parts inventories and evaluation of auxiliary systems. “You really cannot assume a baseline reliability after a prolonged shutdown and deferred maintenance,” Brun said.
Technicians look for oil leaks, corrosion, erosion, shaft sagging and evidence that preservation procedures were neglected during shutdown periods. Heavy rotors that have remained stationary for years can develop bowing, creating vibration problems during startup. Lubrication systems, cooling systems and seals frequently prove more problematic than the compressor itself. In many cases, operators discover that auxiliary equipment has deteriorated significantly even when the primary turbomachinery appears serviceable. www.compressortech2.com
VENEZUELA’S LESSONS
ALL PHOTOS: EBARA ELLIOTT ENERGY
ELLIOTT TURBO
The hidden risks of idle equipment Long periods of inactivity create predictable failure modes. Dry gas seals can be damaged by moisture and contamination. Lubrication systems often suffer from corrosion or fouling. Control systems may rely on obsolete PLC hardware or relay logic that can no longer be supported. Spare-parts inventories present another challenge. Years of sanctions, supply-chain disruptions and maintenance deferrals often force facilities to cannibalize equipment to keep other units running. “We think about 50% of the machines are operational, but some have been abandoned,” Brun said. “We’re still inspecting these machines one by one to see if they can be repaired or must be replaced.” Beyond mechanical condition, operators must determine whether older machines remain suitable for current process requirements. Changes in gas composition, flow rates and operating conditions can make previously acceptable compressor configurations unsuitable for modern service.
Reverse engineering and modernization When replacement parts are no longer available, reverse engineering becomes an important tool for extending asset life. www.compressortech2.com
Brun emphasized that the goal is not simply to recreate older components but to incorporate modern technologies where possible. Using 3D scanning, dimensional analysis and metallurgical testing, engineers can reproduce critical components while upgrading materials, coatings and aerodynamic designs. “Rebuilding it to the 1980s specifications is a missed opportunity,” Brun said. “You should always evaluate whether you can rerate the aerodynamics, make a better machine, look at different materials and improve reliability and efficiency.” Reverse engineering also plays a role when complete machine replacements are required. Detailed site scanning ensures that new equipment integrates properly with existing piping, utility connections and foundation layouts.
Grid instability threatens reliability One of Venezuela’s most significant operational challenges remains electrical reliability. Frequent power interruptions can create serious risks for motor-driven compressors and other rotating equipment. Loss of electrical power can interrupt lubrication systems, cooling systems and dry gas seal support systems, potentially causing catastrophic damage. Brun noted that steam turbine and gas turbine drives can provide a degree of insulation from grid instability, but where electric motors remain necessary, operators must invest in robust backup systems. Uninterruptible power supplies, battery banks and automated shutdown sequences help ensure equipment can safely coast down during electrical disturbances. “Even a small grid anomaly should trigger a controlled shutdown rather than waiting until the last moment,” Brun said. He added that Venezuela’s focus on stabilizing its electrical infrastructure is a necessary Klaus Brun, vice president of products and technology at Ebara Elliott Energy.
prerequisite for restoring reliable energy production.
Data-driven recovery Modern diagnostics are playing an increasingly important role in infrastructure restoration projects. Many legacy machines lack even basic condition-monitoring systems, making upgrades a priority. Brun recommends installing modern vibration monitoring, bearing-temperature monitoring and surge-control systems before attempting to return critical equipment to service. Once machines are operating, operators can use advanced vibration analysis, including Bode plots, orbit analysis and waterfall plots, to identify developing problems before they result in failures. “Data is really your most valuable asset,” Brun said. Non-destructive testing methods such as ultrasonic inspection can also identify subsurface cracking and other defects that may not be visible during routine inspections.
Workforce challenges remain Technology alone will not solve the problem. Like many regions experiencing infrastructure recovery, Venezuela faces a shortage of experienced personnel after years of workforce migration and limited training opportunities. Brun said operators need technicians skilled in precision alignment, seal installation, vibration diagnostics and modern control systems. To address those gaps, EEE relies heavily on on-the-job training, standardized maintenance procedures and remote support capabilities. “When operators understand the turbomachinery—not just its function but the operational details and physics— reliability comes back and unplanned outages decline,” Brun said.
Lessons beyond Venezuela While Venezuela presents an extreme example, Brun believes many of the lessons apply equally to aging compressor stations, AUGUST-SEPTEMBER 2026 | COMPRESSORTECH2 | 31
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VENEZUELA’S LESSONS ELLIOTT TURBO
Experienced technicians and disciplined maintenance practices remain essential to restoring and maintaining aging turbomachinery fleets.
gas processing plants and LNG facilities worldwide. Among the most important: never underestimate the scope of recovery work. Projects initially expected to require only minor repairs often expand dramatically
once auxiliary systems, controls and supporting infrastructure are fully evaluated.
Don’t forget auxiliaries He also cautioned operators to secure longlead replacement parts well before outages
begin, noting that some components can require six to 10 months for delivery. Perhaps most importantly, Brun urged operators not to focus solely on the compressor itself. “Auxiliaries kill reliability,” he said. “Everybody obsesses about the compressor or the steam turbine, but it’s usually the auxiliary systems that cause the trip.” As energy infrastructure ages globally, the experience gained from restoring neglected assets may become increasingly valuable. For operators facing deferred maintenance, workforce shortages and aging equipment, Venezuela’s recovery effort serves as a reminder that reliable production begins with disciplined inspection, modernization and long-term planning. CT2
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VOC EMISSIONS
COLDSTREAM ENERGY
Eastern Gas Compression Roundtable presentation highlights pressure swing adsorption approach aimed at reducing VOCs, detonation and downtime.
ColdStream Energy details MaCH4 technology for lean fuel gas, NGL recovery at compressor stations
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fuel gas conditioning technology designed to improve engine performance, reduce VOC emissions and recover higher-value natural gas liquids is beginning to move from pilot testing into commercial deployment within the natural gas compression market. During a technical presentation at the Eastern Gas Compression Roundtable in Pittsburgh, Mathias Schlecht, president and CEO of ColdStream Energy, and Matt Thompson, senior vice president of Sales and Marketing for the company, outlined the MaCH₄ technology platform, which uses pressure swing adsorption to generate lean fuel gas at compressor stations. The speakers said the technology was developed to address a longstanding operational challenge facing gas compression operators — running large-bore engines on increasingly rich field gas streams. “When we talk about burning rich gas in engines, very rich gas means you have higher VOC emissions,” Schlecht said during the presentation. “You’re also destroying value by creating additional emissions.”
“If you’re on the producer side, less gas makes it through the pipeline to the sales point,” he said. “If you’re a midstreamer, it means you lose compression fees because you don’t have the volume going through the station.” The MaCH4 system is designed to remove heavier hydrocarbons from the fuel stream while simultaneously recovering valuable NGLs. The technology relies on pressure swing adsorption, or PSA, a process that selectively captures heavier hydrocarbons on an engineered adsorbent material at high During a technical presentation at the Eastern Gas Compression Roundtable in Pittsburgh, Mathias Schlecht, president and CEO of ColdStream Energy, and Matt Thompson, senior vice president of Sales and Marketing for the company, outlined the MaCH4 technology platform, which uses pressure swing adsorption to generate lean fuel gas at compressor stations.
pressure before releasing them at lower pressure. The remaining leaner methanerich gas can then be used as engine fuel. Schlecht said the approach differs from more traditional JT skids or mechanical refrigeration units commonly used for fuel gas conditioning.
Improving NGL recovery rates Current approaches often provide only limited reductions in BTU content and may still leave operators dealing with elevated methane numbers, VOC emissions and detonation risk, according to the presentation. By comparison, the MaCH4 process is intended to produce near-pipeline-quality lean fuel gas while improving NGL recovery rates. Schlecht said the system has demonstrated recovery rates of approximately 60% for ethane, 90% for propane and as much as 98% for butanes and heavier hydrocarbons.
Detonation issues According to the presenters, richer fuel streams can contribute to increased engine derates, detonation events, downtime and lost throughput, particularly during high ambient temperature conditions in major producing regions such as Texas and Oklahoma. Schlecht said some operators have reported as much as 3% downtime tied to detonation issues associated with rich fuel gas. www.compressortech2.com
AUGUST-SEPTEMBER 2026 | COMPRESSORTECH2 | 35
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VOC EMISSIONS
COLDSTREAM ENERGY
The presenters also emphasized that the system does not require additional compressors or generation equipment because it operates using the existing pressure differential between compressor station suction and discharge headers. “There’s no rotating equipment,” Schlecht said. “No additional compression involved.” That design approach, the speakers said, can reduce both operating complexity and maintenance requirements compared to more conventional refrigeration-based systems. Because the process relies primarily on pressure differentials already available at the compressor station, the company believes the system can be deployed with relatively low parasitic energy losses while avoiding many of the operational issues associated with rotating refrigeration equipment.
Gas composition Schlecht explained that richer associated gas streams have become increasingly common as operators continue developing liquids-rich shale formations. In many producing regions, gas composition can fluctuate substantially over time as wells mature or as gathering systems integrate multiple supply sources. Those variations can create operational headaches for compressor station operators attempting to maintain stable combustion conditions across engine fleets. “We see methane numbers moving around all the time,” Thompson said during the presentation. “That variability is what causes problems for operators.” The speakers noted that modern highhorsepower reciprocating engines are often tuned aggressively to maximize efficiency and emissions performance, leaving less tolerance for sudden swings in fuel composition. As a result, fuel quality management is becoming increasingly important as operators attempt to reduce methane emissions, improve reliability and maintain throughput. According to Thompson, some operators currently attempt to address fuel variability 36 | COMPRESSORTECH2 | AUGUST-SEPTEMBER 2026
by blending leaner gas streams into richer supplies or by manually adjusting engine settings. However, those approaches can create additional operational complexity and may not fully eliminate detonation issues. The presenters argued that conditioning the fuel itself can provide a more stable long-term solution. Schlecht described the PSA process as effectively separating the gas stream into two products — a lean methane-rich fuel stream optimized for combustion and a concentrated NGL stream that can potentially be monetized. The heavier hydrocarbons removed from the gas stream can include propane, butanes and natural gasoline components that may carry significant value depending on local NGL pricing and infrastructure access. “We’re not just fixing the fuel gas problem,” Schlecht said. “We’re also recovering a product stream that otherwise gets burned.” The speakers said that dynamic becomes particularly important as operators face increasing pressure to improve emissions performance. In some jurisdictions, lowering VOC emissions may help facilities avoid triggering more stringent air permitting thresholds. Schlecht noted that reducing VOC emissions can also help operators manage community relations and regulatory scrutiny around compressor stations and midstream infrastructure. The presenters additionally emphasized that the technology was designed specifically for field deployment rather than laboratory-only applications.
“We’re not just fixing the fuel gas problem. We’re also recovering a product stream that otherwise gets burned.” MATHIAS SCHLECT, CEO, ColdStream Energy.
The company said the system has now accumulated more than 15,000 operating hours at a compressor station near Oklahoma City, including approximately 3,000 hours operating as a full-scale commercial fuel gas system.
Commercial deployment According to Schlecht, the technology was initially validated through laboratory work conducted in partnership with the University of South Carolina before progressing through pilot and commercial-scale deployment phases. He said one of the major engineering challenges involved identifying adsorbent materials capable of handling varying gas compositions while maintaining consistent separation performance over extended operating periods. Thompson later discussed several commercial deployment scenarios where the company believes the technology could provide value. Those applications include upstream field compression, centralized gathering systems, gas lift operations and midstream compressor stations operating on rich associated gas. The speakers also suggested the technology could become increasingly relevant as electrification pressures grow within the compression industry. While electric motor-driven compression continues expanding in some regions, many remote facilities still lack reliable grid access or sufficient electrical infrastructure to support large-scale electrification. As a result, engine-driven compression remains critical across much of the upstream and midstream sector. “At the end of the day, engines aren’t going away anytime soon,” Thompson said. The presentation also touched on the growing overlap between compression technologies and distributed power generation. Schlecht noted that many of the same fuel-quality challenges affecting compressor station engines are also becoming relevant for gas-fired distributed generation systems, particularly in oilfield microgrid and behindthe-meter power applications. CT2 www.compressortech2.com
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LNG DEMAND WILLIAMS
Projects target rising natural gas demand from LNG exports, power generation and data centers
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illiams executives said the company’s $5.5 billion acquisition of Momentum Midstream will strengthen its position in the Haynesville Shale while supporting a new wave of pipeline expansions tied to growing LNG exports, power generation and data center development along the U.S. Gulf Coast. Speaking during the company’s second-quarter earnings call, President and CEO Chad Zamarin said the acquisition significantly expands Williams’ gathering footprint in East Texas and Louisiana while creating opportunities for new transmission projects that connect growing natural gas supplies with rapidly expanding demand centers. “The Haynesville is expected to grow by over 10 Bcf per day, and LNG exports are expected to double from where they are today,” Zamarin said. “The combined Williams and Momentum assets will form the backbone that connects our country’s fastest-growing supply basin with our fastest-growing demand corridor.” The acquisition adds approximately 6 Bcf/d of gathering capacity and more than 4 Bcf/d of take-or-pay pipeline capacity to Williams’ existing Haynesville network. Executives said the combined system will enhance the company’s ability to supply LNG export terminals, electric utilities and industrial customers across the Gulf Coast.
Expansion projects announced Alongside the acquisition, Williams unveiled two major expansion projects designed to move additional Haynesville
www.compressortech2.com
Williams builds out Haynesville-to-Gulf Coast gas network production to downstream markets. The first, Shelby Connector, will link the Momentum gathering system with Williams’ Louisiana Energy Gateway (LEG) pipeline network. The project will initially transport up to 750 MMcf/d, with an in-service target during the first half of 2028. Williams said the pipeline could ultimately be expanded to 1.5 Bcf/d. The second project, Delta Access, is planned as a fully contracted transmission pipeline extending along the Transco corridor. Initial capacity is expected to reach 2.25 Bcf/d, with service beginning in early 2029 and expansion potential to 3.5 Bcf/d. According to Williams, customer commitments already include both LNG export facilities and power generation projects along the Louisiana Gulf Coast. Executives said both projects reflect continued growth in natural gas demand from LNG facilities and electric power. Williams also highlighted increasing demand from power generation, including data centers, as a major driver of future infrastructure investment. During the quarter, the company signed agreements for the Lighty Access and Garden Connector pipeline expansions serving Pennsylvania and New Jersey and increased the planned capacity of its Transco Power Express expansion in Virginia to 800 MMcf/d to accommodate growing electric load and data center development. The company also commercialized an extension of its Line 200 pipeline, originally
developed to serve the Woodside LNG project, adding a lateral to supply new power demand in the Lake Charles, Louisiana, area. Chief Operating Officer Larry Larson said Williams continues to see strong customer interest across the Transco system.
Behind-the-meter power Beyond its traditional pipeline business, Williams said its Power Innovation business reached an important milestone with the completion of Phase One of the Socrates project, which delivers 200 MW of behindthe-meter power for a customer. Executives said the project entered service less than 18 months after commercialization and remains on schedule and within budget. The company expects to complete the next phase before year end while pursuing additional projects serving hyperscale data centers. Zamarin said Williams continues discussions with multiple customers and expects to commercialize additional projects before the end of the year. Williams raised its full-year 2026 adjusted EBITDA guidance to $8.3 billion-$8.5 billion, reflecting contributions from the Momentum acquisition and stronger underlying business performance. CT2 Williams executives said the company’s $5.5 billion acquisition of Momentum Midstream will strengthen its position in the Haynesville Shale. IMAGE: MOMENTUM MIDSTREAM
AUGUST-SEPTEMBER 2026 | COMPRESSORTECH2 | 39
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LUBRICATION
PREVENTIVE MAINTENANCE
Sloan emphasizes preventive maintenance, monitoring for lubrication systems Eastern Gas Compression Roundtable session highlights how overlooked lubrication components can trigger major compressor failures.
42 | COMPRESSORTECH2 | AUGUST-SEPTEMBER 2026
cylinder discovered during a field inspection in Los Angeles. According to the presenters, the compressor package had reportedly operated for years with minimal lubricationsystem maintenance.
Warning signs The inspection revealed multiple warning signs, including aging divider blocks, outdated monitoring hardware and improperly oriented check valves. The cylinder itself suffered a deep internal gouge after a component failure inside the compressor. While the exact initiating failure could not be conclusively identified, the presenters concluded that the lubrication system had likely deteriorated significantly over time. According to C.J. Sloan, testing on aging divider blocks frequently reveals pressures outside acceptable operating ranges. “If you were to test those blocks, they probably would not even come close to the correct pressures,” he said. The presentation highlighted divider blocks as one of the most misunderstood components in force-feed lubrication systems. Divider blocks meter and distribute precise lubricant volumes to compressor Modern lubrication monitoring can provide greater visibility into lubricant delivery and system performance. Sloan presenters emphasized that pressure alone does not confirm proper lubricant flow.
cylinders and packing assemblies. According to the Sloan presenters, operators often mistakenly assume divider blocks will last for the full service life of the compressor package. Instead, presenters stressed that divider blocks require periodic inspection, testing and replacement as part of a documented maintenance strategy. The session also emphasized the importance of flow monitoring rather than relying solely on pressure indications. According to the presenters, some legacy systems still utilize basic “go/nogo” monitoring devices that only confirm whether lubricant movement exists within the system. Modern monitoring systems using proximity switches and cycle-count monitoring provide significantly better visibility into actual lubricant delivery rates. The presenters repeatedly emphasized that pressure alone does not confirm proper lubrication flow. “Pressure is not an indication of flow in lubrication systems,” C.J. Sloan said while discussing lubrication monitoring practices.
Overlooked issues The discussion also covered the cascading failures that can occur when lubricationsystem components begin deteriorating. Improperly oriented or degraded check valves can eventually allow process gas to migrate into lubrication tubing and divider blocks, ultimately causing divider-block failure and disrupting lubricant delivery. According to the presenters, these failures may develop slowly over time, making routine inspections especially important. www.compressortech2.com
PHOTOS: SLOAN LUBRICATION SYSTEMS
C
ompressor lubrication systems may represent a relatively small portion of a reciprocating compressor package, but neglecting them can lead to expensive failures, cylinder damage and extended downtime. That was the central message from Eric Sloan, director of marketing and business development; Brian Sloan, CEO; and C.J. Sloan, CTO of Sloan Lubrication Systems, during a recent discussion on compressor lubrication maintenance and reliability. The session focused on compressor force-feed lubrication systems, maintenance practices, monitoring approaches and common field failures affecting reciprocating compressors operating across the natural gas industry. Presenters argued that lubrication systems are frequently overlooked during maintenance planning despite their critical role in compressor reliability. “Lubrication systems are just such a tiny part of this whole industry, and I think that they kind of fly under the radar,” Eric Sloan said during the discussion. “They get ignored a lot when people are talking about compressor packages. They get ignored a lot during preventative maintenance.” The presentation emphasized that many lubrication-related failures stem not from catastrophic component defects, but from aging equipment, poor monitoring practices and insufficient preventive maintenance. One case study presented during the session involved a severely damaged compressor
LUBRICATION
PREVENTIVE MAINTENANCE
Divider blocks meter and distribute lubricant to compressor cylinders and packing assemblies.
PHOTOS: SLOAN LUBRICATION SYSTEMS
The Sloan team also discussed overlubrication issues, which can create their own operational problems. Excessive lubrication can contribute to carbon buildup, valve contamination and reduced compressor efficiency. The presenters said operators sometimes unintentionally over-lubricate compressors in response to concerns about wear or inadequate lubrication. Instead, the Sloan team encouraged operators to verify actual flow rates, validate system settings and document lubrication adjustments carefully. The session also highlighted the growing importance of training and operator familiarity with lubrication systems. Presenters acknowledged that lubrication systems can appear intimidating to newer technicians because of the
number of components involved, but argued that the systems themselves remain relatively straightforward once operators understand how the components interact. C.J. Sloan said lubrication systems can appear intimidating to newer technicians because of the number of components involved, but argued that the systems themselves remain relatively straightforward once operators understand how the components interact. “There’s not a lot of complexity to it,” he said. “There are some very high precision components or tight tolerances, but really our objective is to make sure that people understand them well enough that they’re comfortable.” The presentation encouraged operators to maintain accessible reference materials, document maintenance procedures and establish preventive maintenance programs before failures occur. According to the presenters, many catastrophic lubrication failures can be
avoided through routine inspections, periodic divider-block testing and proper system monitoring. The presenters also stressed the importance of evaluating older compressor packages that may still be operating with original lubrication-system components decades after installation. One case study discussed during the session involved a compressor package that had reportedly operated for roughly 20 years with little lubrication-system maintenance before experiencing a major failure. Brian Sloan said aging lubrication-system components eventually require inspection, refurbishment or replacement as part of long-term compressor maintenance planning. For many operators, the presenters argued, lubrication-system reliability remains one of the simplest and most cost-effective ways to protect compressor cylinders, packing assemblies and other critical rotating equipment components. CT2
EMISSIONS
METHANE CONTROL
Operators rethink methane control, according to ZEVAC CEO Doug Sahm.
Known-source capture gaining traction
Why operators are capturing gas Sahm said the biggest driver behind capture projects today is not necessarily direct methane regulation, but air permitting. In many cases, operators are implementing capture systems because state air permits increasingly require “reasonably available” or “best available” control technologies to limit emissions from new or expanded facilities. That permitting pressure is shaping project economics and equipment decisions, particularly for operators trying to expand throughput or add horsepower without triggering a more stringent Title V permitting threshold. “A ton of facilities got designed just under 44 | COMPRESSORTECH2 | AUGUST-SEPTEMBER 2026
Title V,” Sahm said. “Nobody wants to be Title V. If you have a choice, you stay under.” That has made methane capture an increasingly useful tool for operators looking to grow capacity without reopening complex air permit reviews. By capturing emissions from rod packing, pneumatic controllers and blowdowns, operators can preserve emissions totals while increasing throughput. Sahm said operational considerations are also driving adoption, especially where capture systems can improve maintenance planning and reduce downtime. Rod packing, in particular, can offer a compelling economic case when capture systems allow operators to extend maintenance intervals and avoid costly changeouts. “If you can even avoid one compressor packing change, you can pay for the system,” he said.
in the context of emissions reduction, Sahm argued the harder challenge is not horsepower — it is controls. “This is not a power challenge, it is a controls challenge,” he said. That is especially true for low-flow sources such as rod packing vents and pneumatic controllers, where flow rates are small but operational tolerances are tight. Sahm said the real challenge lies in managing backpressure, avoiding air intrusion and ensuring systems fail safely without disrupting core equipment performance. For rod packing systems, he said low positive backpressure is essential. “Low positive backpressure is pretty much the key to all of these,” Sahm said. “You do not want air intrusion. But if you put high backpressure, it finds the way out.” That creates a narrow operating band that requires tight control logic, pressure relief considerations and buffer capacity to absorb pressure excursions. In practice, Sahm said, what appears to be a simple emissions project can quickly become a broader controls and process engineering exercise.
The engineering challenge While methane capture is often discussed Gas recovery equipment can transfer product from an isolated or venting system back into operating infrastructure rather than releasing it to the atmosphere.
Source-level vs. station-level
ALL PHOTOS: ZEVAC
D
oug Sahm, CEO and co-founder of ZEVAC, delivered a pragmatic message to operators and engineers: methane capture is no longer primarily a detection problem — it is an engineering and operations problem. Speaking at a recent industry event, Sahm said the most effective emissions control strategies begin not with satellites or sensors, but with “known sources” already identified in facility design, including rod packing vents, pneumatic controllers and blowdown systems. “We do not try to find anything,” Sahm said. “We start from what we call known sources, or design venting. These are things you do not have to go find — it’s a P&ID that says line to atmosphere.” That distinction framed Sahm’s central argument: operators looking to reduce methane emissions can make faster, more practical gains by targeting designed vent sources already built into compressor stations, rather than relying solely on leak detection technologies.
One of Sahm’s clearest themes was that capture projects become far more manageable — and more scalable — when designed at the source level rather than across an entire station. Station-wide systems that aggregate rod packing, pneumatics, blowdowns and other vent sources into a single recovery network can work, Sahm said, but they quickly become complex engineering projects with more failure modes, more integration risk and higher installed cost. www.compressortech2.com
EMISSIONS
METHANE CONTROL
Closed-vent gas recovery systems can capture emissions from known sources including compressor rod packing vents, pneumatic controllers and unit blowdowns.
By contrast, smaller source-level systems placed directly at individual emissions points can be standardized, replicated and scaled across fleets. “If you go to source-level solutions, you can scale it out,” Sahm said. “You don’t end up in a bespoke engineering project for every single site.” That distinction becomes especially important for large operators trying to roll out methane control across hundreds or thousands of assets. Sahm described one operator with roughly 4,000 compressor units that needed a repeatable solution rather than a custom engineering exercise at every site.
Sahm also cautioned operators against treating methane capture as a standalone brownfield retrofit project unless it can be folded into a larger capital scope. Over the last decade, he said, ZEVAC has seen retrofit projects where installed costs ballooned to five to seven times the cost of the capture equipment itself once piping, controls, safety integration and field construction were included. “You might have a $50,000 capture system... and the project cost is now like $380,000 or $400,000,” Sahm said. His recommendation: bundle capture into larger site upgrades, compressor additions or procurement packages wherever possible. “If you do capture as its own project, the economics will never work out,” he said. That same logic applies to new equipment. Sahm said the most costeffective way to implement methane capture is to build it into compressor procurement specifications from the outset,
where the added cost becomes marginal compared with the overall package.
Built into the spec For Sahm, the lesson from a decade of methane capture projects is straightforward: the most successful implementations are designed early, standardized aggressively and integrated into the broader equipment package rather than treated as an afterthought. “The best way this is done is when you’re in greenfield, at a source level, and you push it down your supply chain,” he said. That approach, he argued, not only reduces emissions, but also avoids measurement headaches, improves operational predictability and gives operators a more scalable path to compliance. Sahm’s message was simple: stop treating methane capture as a one-off emissions fix and start treating it as a design and operations discipline. CT2
ADVERTORIAL
PARTS LIBERTY: BUILDING A PARTS PROGRAM FOR EQUIPMENT INDEPENDENCE By Brian Wadas, Executive Vice President at Blackstone Industrial
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oday’s rotating equipment operators face a different challenge than they did just a decade ago. Aging fleets, longer OEM lead times, supply chain volatility, and increasing pressure to maximize asset life are forcing organizations to rethink how they manage critical spare parts. At Blackstone Industrial Services, we believe the future of aftermarket support is no longer defined by inventory alone, it is defined by information. That belief is the foundation of our Parts Liberty Program. We are building something foundational: a digital library of rotating equipment components designed to give operators greater visibility, flexibility, and alternatives to traditional parts supply models for their rotating equipment. As equipment ages and OEMs merge, shift focus, or disappear altogether, critical supply chain gaps continue to emerge. These gaps must be addressed to keep equipment maintained, operational, and reliable. This initiative is about more than parts supply and data acquisition management. It represents a transformation in how industrial fleets are maintained, supported, and sustained over time.
THE CONCEPT
At the core of Parts Liberty is a simple but powerful idea: every piece of rotating equipment has a story, and that story should be captured, structured, and leveraged to improve long term availability and reliability. Historically, operators have managed their spare parts utilizing single or limited sourcing suppliers. They relied heavily on the OEMs, or their fragmented documentation, manuals, and facility
knowledge that lived on bookshelves, spreadsheets or in the minds of experienced personnel. The result has been inefficiency, equipment downtime held hostage by long lead times and increased operational risk. At Blackstone, we are changing that by working with our customers to build digital parts libraries tailored to their rotating equipment fleets, from centrifugal and reciprocating compressors to gas and steam turbine spares. Whether it is seals, pistons, bearings, or bolting, the component information can be categorized by type, such as consumables, wear parts, capital spares, then cross referenced
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identify parts considered high-risk and proactively plan for equipment outages and maintenance strategies. The Parts Liberty’s strategy aligns inventory with reality: ● H igh-frequency consumables can be pooled and stocked. ● W ear parts are aligned and can be kitted for maintenance intervals. ● C apital spares can be strategically expedited and stored to support unforeseen or planned outage.
WHAT’S HAPPENING IN OUR SPACE The aftermarket parts industry can be difficult to navigate due to rapid change, driven by three forces:
1. AGING FLEETS AND OEM GAPS
Final quality checks on re-engineered API 617 forged overhung compressor rotor
with maintenance cycles to help navigate operational criticality. This structured approach enables supply chain and operations teams to address critical questions: ● Which parts should be maintained in inventory versus sourced on short notice when needed. ● Which parts carry the highest operational risk due to supply chain constraints. ● Where OEM dependency could create operational vulnerability. By capturing this knowledge, we are turning spare parts into a strategic asset rather than a logistical nightmare.
PARTS AS ASSETS, NOT JUST INVENTORY
Not all parts are the same. A seal kit might be relatively inexpensive and easy to source, while a rotor or diaphragm may require months, or even yearlong lead times which could result in millions of dollars in downtime risk. Our approach focuses to identifying critical assets and understanding which components truly impact operational continuity. By mapping installed-base intelligence across fleets, we can help to
Many refining and petrochemical facilities operate equipment that is decades old. In many cases, OEM support has become limited, prohibitively expensive, or no longer available. We consider these units to be part of an orphaned fleet. The OEM parts are obsolete and difficult to find. This has created a growing demand for re-engineering and alternative supply solutions.
2. SUPPLY CHAIN VOLATILITY Global disruptions have exposed the vulnerabilities of traditional supply chains. Extended lead times for parts are no longer operationally acceptable, pushing operators to seek localized, more flexible and diversified manufacturing solutions.
3. LOOKING AT LIFECYCLE COST Operations teams are moving beyond transactional purchasing toward lifecycle optimization. They are looking for partners who can help extend asset life, improve reliability, and reduce total cost of ownership. Parts Liberty is at the intersection of these trends. By combining deep fleet knowledge with engineering and supply chain capabilities, we are redefining what aftermarket support looks like moving from reactive sourcing to proactive lifecycle management.
TECHNOLOGY AS AN ENABLER
The science behind manufacturing is evolving faster than at any point in the last fifty years. Material science, additive manufacturing, digital metrology,
computational analysis, and artificial intelligence are fundamentally changing how industrial components can be designed, manufactured, inspected, and supported. As these changes occur, we are continuously adapting our approach, testing new methods, and challenging traditional assumptions. A key area of focus is re-engineering and digital part replication. By leveraging 3D scanning, advanced modeling, and metallurgical analysis, we can recreate critical components with precision and speed. More importantly, this is not simply about duplicating parts. It is about improving them where possible. We are also actively exploring additive manufacturing (3D printing) as part of our toolkit. While not every component is suitable for 3D printing, the potential is significant. We do not pursue technology because it is new. We pursue it because it solves real customer problems. Every new process, material, or manufacturing technique must prove its value through engineering validation and field performance before becoming part of our solution portfolio. By leveraging our exposure to a wide range of OEM parts we are able to identify limitations, compare alternatives, and recommend more effective solutions.
INDEPENDENCE THROUGH CAPABILITY
Parts Liberty is ultimately about giving industrial operators greater freedom: freedom from obsolete documentation, extended lead times, single-source dependency, and uncertainty. By combining engineering knowledge, digital asset intelligence, and advanced manufacturing technologies, we are helping build a more resilient future for rotating equipment. That is what independence looks like. This aligns directly with our broader mission: deliver operational continuity, reduce supply chain risk, and empower customers with optimized asset solutions. Parts Liberty is building the foundation for that future, one part, one asset, and one fleet at a time.
www.blackstoneindustrial.com
RNG
COPELAND’S VILTER VSGX
Copeland targets changing RNG market with standardized compressor platform Vilter VSGX compressor responds to larger digester projects. By Jack Burke
T
he growing renewable natural gas market is creating a wider range of compression requirements as developers pursue food waste projects, co-digestion and centralized processing models alongside traditional landfill and dairy digester applications. Copeland is targeting those changing requirements with its new Vilter VSGX compressor, a standardized single-screw platform designed for mid- to large-scale digester projects. The company said the compressor was developed in response to two persistent challenges in renewable natural gas development: upfront capital costs and equipment lead times. Caroline Limbaugh, product manager for Copeland’s Vilter brand, said the company focused on packaging and standardization rather than redesigning the core singlescrew compressor. “The design changes really come down to unit packaging changes and product standardization,” Limbaugh said. “The singlescrew compressor, which sets the industry standard for reliability, remains the same.” Copeland said the changes can reduce initial capital costs by double-digit percentages compared with previous configurations while retaining the core compressor technology already used across the company’s renewable gas installations.
Standardization targets cost and lead times The VSGX incorporates several manufacturing and packaging changes 48 | COMPRESSORTECH2 | AUGUST-SEPTEMBER 2026
Copeland’s Vilter VSGX single-screw compressor is designed for mid- to large-scale biogas digester applications. IMAGE: COPELAND
intended to simplify the compressor package. Those include optimization of the oil circuit, new oil filters and a simplified programmable logic controller and humanmachine interface. Copeland also developed a cold-weather design that eliminates the oil cooler heater while allowing the unit to start at temperatures as low as -20 F. The larger change, however, is the move to a configure-to-order model. VSGX packages use standardized drawing packages and predefined equipment configurations. That allows individual units to bypass much of the custom engineering process typically associated with industrial compressor packages. The approach also gives Copeland greater economies of scale on standardized components. “Standard drawings will allow the customer’s engineering to proceed without having to wait for custom drawings to be completed,” Limbaugh said. Copeland currently is offering a 30week lead time for the VSGX and intends to shorten that schedule further. Equipment delivery has become an increasingly important issue for RNG developers as projects compete for compressors, gas upgrading equipment and other specialized components. By completing standard drawings in advance, project engineers can move forward with portions of facility design while the compressor package is being manufactured.
Moisture and contaminants also can create difficulties for compression equipment. Copeland said more than 700 Vilter compressor units currently are operating in RNG applications, providing the company with an installed base for evaluating compressor performance under varying gas conditions. The Vilter single-screw design uses slide valve technology to adjust compressor capacity as flow changes. The compressor can turn down to 20% of maximum flow without requiring a variable frequency drive, according to Limbaugh. That capability can be particularly important at digester projects where gas production fluctuates. The compressor’s internal design also differs from conventional twin-screw technology. Vilter’s single-screw rotor does not have metal-to-metal contact between the primary compression components — the rotor and gate rotor. Limbaugh said the configuration provides greater resilience when contaminants enter the gas stream. The compressor uses Ryton-to-metal contact at the rotor interface and is designed with balanced forces. Copeland said the arrangement reduces loads on the bearings and contributes to longer bearing life and lower overhaul frequency.
Changing biogas conditions
Compression technology choices
Unlike conventional pipeline natural gas, raw biogas can experience changes in flow and composition based on feedstock, digester conditions and other operating variables.
RNG developers generally evaluate singlescrew, twin-screw and reciprocating compressor technologies, depending on flow, pressure and project requirements. www.compressortech2.com
RNG
COPELAND’S VILTER VSGX
Limbaugh said reciprocating compressors have a relatively large number of moving and wearing components, which can increase parts replacement requirements and the risk of unplanned downtime. Oil consumption and gas pulsation also can require additional consideration in RNG applications. Twin-screw compressors are closer
to single-screw technology in terms of application, but the designs have important mechanical differences. According to Limbaugh, twin-screw compressors experience both axial and radial forces and use male and female rotors with metal-to-metal contact. Those characteristics can affect bearing life and overhaul frequency. Twin-screw systems also may require a VFD to achieve the level of turndown needed for variable biogas flows. By comparison, Copeland’s singlescrew design uses balanced forces and can reduce capacity to 20% of maximum flow through its slide valve. The design also provides access to key compressor components for inspection and is intended to operate with relatively low oil consumption.
Targeting a broad range of digesters The VSGX has a compressor flow range of 800 to 2,100 scfm.
That corresponds to raw biogas flows of approximately 550 to 1,600 scfm, allowing the compressor to serve dairy, municipal wastewater and food waste digester applications, Limbaugh said. The selected compressor sizes also allow VSGX packages to operate at 480 V. Remaining at low voltage is desirable for many digester operators because it can simplify electrical infrastructure compared with equipment requiring medium-voltage systems. Copeland sees the market for those compressor sizes expanding as RNG project development evolves. “We’re seeing a trend toward smaller landfills, as well as the emergence of more co-digestion or food waste projects, which tend to be on the medium to large side of digesters,” Limbaugh said. Developers also are evaluating new project structures intended to improve the economics of smaller gas sources. CT2
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DIGITAL SOLUTIONS BURCKHARDT
The future of compressor maintenance, digitally enhanced, empowered
F
or more than a century, reciprocating compressors have been used across industrial gas compression applications. In oil and gas production, refining and petrochemicals, marine transportation and emerging hydrogen applications, the machines frequently operate in demanding environments where unplanned downtime can have significant operational consequences. Traditionally, compressor reliability has been supported through mechanical design, scheduled maintenance and the experience of skilled technicians. The operating environment, however, is changing. Operators face pressure to reduce costs, improve efficiency, lower emissions and maintain equipment availability while, in many cases, managing a shrinking pool of experienced compressor specialists. Digital monitoring and data analytics are increasingly being incorporated into compressor maintenance strategies in response to those pressures. Burckhardt Compression is among the compressor manufacturers applying data analytics and cloud-based technologies to service and maintenance. The objective is not to replace traditional compressor service, the company said, but to provide operators with additional information that can support a move from reactive and timebased maintenance toward condition-based and predictive asset management.
Modernizing maintenance Compressor service traditionally has followed a relatively linear process involving installation, commissioning, inspections, scheduled overhauls and spare parts replacement. Maintenance intervals frequently are defined by operating hours or calendar 50 | COMPRESSORTECH2 | AUGUST-SEPTEMBER 2026
Digital monitoring and predictive tools are changing service, reliability and maintenance strategies for reciprocating compressors.
Burckhardt Compression is among OEMs using data analytics for maintenance.
schedules, while troubleshooting may rely heavily on site personnel and manual interpretation of operating data. The approach can have limitations. Time-based maintenance may result in components being replaced before the end of their useful service life to minimize the risk of failure. At the same time, unexpected operating conditions can cause components to deteriorate between scheduled maintenance intervals. Both scenarios can increase costs or contribute to unplanned downtime. Changes in sensor technology, industrial connectivity and cloud computing have expanded the amount of compressor data available for analysis. Workforce changes also are influencing maintenance strategies. Fewer specialists may be responsible for
larger numbers of assets, while experienced technicians retiring from the industry can take decades of machine-specific knowledge with them. Burckhardt has integrated digital monitoring into its service offerings to provide continuous visibility into compressor behavior, earlier identification of developing problems and remote access to compressor specialists.
Why reciprocating compressors suit condition monitoring Reciprocating compressors are mechanically complex machines with wear characteristics influenced heavily by operating conditions. Valves, packings, pistons and bearings do not necessarily degrade at a constant www.compressortech2.com
DIGITAL SOLUTIONS BURCKHARDT
mechanical or process problems before they result in a shutdown. Burckhardt said combining operating data with compressor engineering knowledge and analytics can support maintenance decisions and potentially extend mean time between overhauls.
An integrated digital portfolio
Burckhardt said it has integrated digital monitoring into its service offerings.
rate. Component life can be affected by gas composition, pressure ratios, load changes, start-stop cycles and maintenance practices. As a result, predicting the optimum maintenance interval based solely on operating hours can be difficult. Two compressors of the same design may experience different wear patterns depending on their operating conditions. Those characteristics make reciprocating compressors candidates for conditionbased and predictive maintenance strategies. The machines also frequently serve as critical plant assets. Compressor availability can directly affect production in processing applications, while reliability in marine and gas transportation service is particularly important when maintenance opportunities are limited. Digital monitoring systems can continuously collect data including vibration, pressure, temperature and process parameters. Analysis of those data can provide indications of developing www.compressortech2.com
Burckhardt has developed several digital monitoring systems intended to address different compressor maintenance and troubleshooting requirements. The company’s PROGNOST-NT system provides full-spectrum analysis and an emergency shutdown function. Its cloudbased UP! Insight and UP! Detect platforms are designed for troubleshooting and condition monitoring. The systems differ in function but are intended to supplement conventional compressor service with remote data access and analytics.
Accelerating troubleshooting Troubleshooting a compressor alarm traditionally may require operating data to be collected manually, process conditions to be reconstructed and technical specialists to review the available information. In some cases, site visits are required. UP! Insight uses existing programmable logic controller data to support remote troubleshooting. Because the cloud-based system draws on existing PLC information, additional sensors or modifications to the compressor are not necessarily required. An edge computer collects operating data and makes the information available for analysis. When an alarm or abnormal operating condition occurs, compressor specialists and the operator can review process conditions leading up to the event. The objective is to give maintenance personnel additional context when determining a root cause and reduce reliance on incomplete operating information. Burckhardt said the system can be particularly useful for operators with limited in-house compressor expertise and companies managing large fleets of similar machines.
Condition-based maintenance While UP! Insight is intended primarily to support troubleshooting, UP! Detect focuses on condition monitoring and early fault detection. The system analyzes vibration data collected across the compressor to identify potential problems including bearing failures, loose crosshead-piston rod connections and valve impacts. An unsupervised deep-learning anomaly detection algorithm compares real-time compressor behavior with a learned baseline representing normal operation. Deviations from that baseline can then be identified and localized. According to Burckhardt, the system can identify up to 90% of mechanical failures at an early stage and reduce false alarms by approximately 50% compared with traditional monitoring approaches. Operators also can add pressure and proximity sensors to expand monitoring of valves, packings, piston rings and piston rods. The expanded configuration can support detection of piston rider band wear. The system provides findings and recommended actions through its user interface. Data also can be sent to a customer’s data lake through a cloud application programming interface for companies that conduct their own analysis or integrate compressor information into broader digital systems. Earlier identification of a developing problem can allow maintenance teams to schedule an intervention rather than responding to an unplanned failure.
The loss of compressor expertise The retirement of experienced compressor specialists is another factor driving interest in digital monitoring. Machine behavior that once may have been recognized by an experienced technician during an inspection can be more difficult to identify when fewer specialists are responsible for a larger equipment fleet. Continuous monitoring allows operating trends to be tracked between physical inspections. Burckhardt also offers expert assessments in which compressor AUGUST-SEPTEMBER 2026 | COMPRESSORTECH2 | 51
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DIGITAL SOLUTIONS BURCKHARDT
specialists periodically review collected data and provide additional analysis of machine behavior. An alarm-forwarding service allows company specialists to review unexpected operating conditions and advise customers on possible next steps. For example, elevated vibration can indicate a developing mechanical problem, but it also may reflect an operating condition that does not require the compressor to be opened immediately. Additional operating data can help maintenance teams determine whether an intervention is warranted. Digital monitoring does not eliminate the need for skilled technicians. Instead, the objective is to focus their time on identified equipment issues and planned maintenance rather than troubleshooting unexpected failures without sufficient operating data.
Cybersecurity Connecting industrial equipment to cloudbased systems also raises cybersecurity and data protection concerns. Burckhardt said its digital platforms use multiple security layers intended to protect data and isolate critical systems. Data are encrypted during transmission and while stored. Cybersecurity also is incorporated into the company’s software development lifecycle, which is certified in accordance with IEC 62443-4-1. The edge platform used by Burckhardt’s UP! digital solutions received IEC 624434-2 certification this year, according to the company. Burckhardt also works with customer information technology departments to address internal cybersecurity requirements and applicable industrial standards.
Toward fully connected compressors The next stage of digital compressor service is expected to involve deeper connectivity and more detailed analytics. Under that model, operational and condition data can be continuously transmitted for analysis and made available to both operators and equipment specialists. 52 | COMPRESSORTECH2 | AUGUST-SEPTEMBER 2026
Monitoring can also extend beyond failure detection, according to Burckhardt.
Monitoring also can extend beyond failure detection. Changes in efficiency can be identified, operating parameters evaluated and wear components monitored to help determine when replacement is required. The latest generation of UP! Detect incorporates vibration, pressure and proximity sensing. Burckhardt said the additional sensor data can help the system distinguish among different valve or packing problems and assess their effect on compressor performance. The company also has developed a patented leakage detection method for reciprocating compressors. Earlier identification of leakage can help operators address efficiency losses and reduce emissions.
From detection to prediction The longer-term objective of digital maintenance is to move from identifying degradation to estimating the remaining useful life of compressor components. Burckhardt has developed a predictive intelligence capability for its PROGNOSTNT monitoring system that uses artificial intelligence and real-time operating data to estimate the remaining useful life of selected components. The system combines current operating information with historical data from similar machines to calculate a projected availability period expressed in days. The technology initially focuses on wear components including valves and packings, which can contribute to unplanned compressor downtime. Integrated with PROGNOST-NT version 21, the predictive system is intended to give maintenance personnel an estimate of when an intervention may be required rather than relying solely on fixed maintenance intervals. That information can allow compressor work to be coordinated with planned
shutdowns and help operators evaluate whether components can remain in service. The technology already is being used in marine applications, according to Burckhardt, where maintenance windows can be limited by vessel schedules. Remaining-life estimates can help crews evaluate whether a compressor is expected to remain in service for another voyage or whether maintenance should be performed at the next available port.
Building the case for digital maintenance The value of digital compressor monitoring ultimately depends on whether the information improves maintenance and operating decisions. Condition monitoring and predictive systems are intended to reduce unplanned downtime, extend maintenance intervals where equipment condition allows and improve the use of maintenance resources. Real-time alerts and periodic reports can provide maintenance teams with additional visibility into compressor condition. Digital monitoring also can support emissions and efficiency objectives. Identifying leakage or deteriorating compressor performance earlier can help operators address energy losses and emissions before conditions worsen. Traditional mechanical service and maintenance will remain central to reciprocating compressor reliability. Digital technologies, however, are giving operators new ways to continuously assess equipment condition and make maintenance decisions based on actual machine behavior. As monitoring and analytics continue to develop, the challenge for operators will be turning growing volumes of compressor data into practical maintenance decisions that improve equipment availability, efficiency and lifecycle performance. CT2 www.compressortech2.com
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LNG
WEBINAR
IMAGE: WOODSIDE
Woodside’s Pluto LNG facility in Western Australia illustrates the type of modern liquefaction plant where compressor selection, driver technology and operating flexibility have become increasingly important.
Smaller trains, electrification and changing feed gas conditions are reshaping compressor requirements as LNG developers seek faster, more flexible projects. By Jack Burke www.compressortech2.com
LNG compression enters a new phase
T
he next generation of LNG projects may look considerably different from the massive, highly customized liquefaction developments that defined much of the industry’s earlier growth. Developers are under increasing pressure to bring capacity online faster, manage capital risk and adapt plants to changing feed gas and operating conditions. Those pressures are influencing liquefaction train size, compressor
selection, driver technology and even how equipment manufacturers work with project developers. For the compression industry, the shift creates a more complicated design challenge. Compressors still sit at the heart of the liquefaction process, but increasingly they must operate across a broader range of conditions and fit within projects designed around flexibility and speed. AUGUST-SEPTEMBER 2026 | COMPRESSORTECH2 | 55
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LNG
WEBINAR
Marybeth Nored, who was product strategy lead for Siemens Energy’s single-shaft centrifugal compressor line, and Mehdy Touil, an LNG specialist widely known in the industry as “the LNG Guy,” discussed those trends during a recent COMPRESSORTech2 webinar examining the technologies and operating issues shaping LNG development. Nored is now in her new role at Williams as a staff engineer. Their discussion highlighted an LNG market that continues to grow but is also becoming more technically diverse.
Smaller trains gain attention One of the clearest changes is the growing interest in smaller liquefaction trains. Historically, LNG developers often pursued economies of scale by building increasingly large liquefaction trains. Large compressor strings and gas turbine drivers became central features of projects designed to produce millions of tonnes of LNG annually from a single train. That approach remains viable, particularly for large baseload LNG facilities. But developers increasingly are considering smaller, modular trains that can be replicated across a project. Touil said speed to market has become an important consideration as developers attempt to capture periods of strong LNG demand. “The key is speed to market,” he said. Rather than designing a highly customized facility around a small number of very large trains, some developers are looking at standardized equipment and repeatable train configurations. The approach can allow construction to proceed in phases and may reduce some execution risks associated with large, one-ofa-kind projects. For compressor manufacturers, however, smaller trains do not A slide from Marybeth Noren’s presentation, outlining some of the trends in LNG.
56 | COMPRESSORTECH2 | AUGUST-SEPTEMBER 2026
necessarily mean simpler applications. Nored said the compressor must still be optimized around the liquefaction process, refrigerant composition and expected operating range. “You still want to optimize the compressor for the process,” she said. The challenge is balancing standardization with the reality that LNG projects often operate under very different conditions.
Every LNG project is different Feed gas composition, ambient temperature, project location and liquefaction technology all influence compressor design. A facility on the U.S. Gulf Coast faces different conditions than an LNG project in the Middle East, Arctic or offshore environment. Even projects using similar liquefaction technologies can have substantially different feed gas compositions. Nored said those differences make early collaboration among process designers, developers and equipment manufacturers particularly important. “You really have to look at each project individually,” she said. Compressors must be designed around Marybeth Nored was product strategy lead for Siemens Energy’s single-shaft centrifugal compressor line.
Located in Calcasieu Parish, Louisiana, between Houston and New Orleans, the Louisiana LNG project constitutes a US$17.5 billion investment. IMAGE: WOODSIDE ENERGY
molecular weight, flow, pressure ratio and the refrigerant mixture used in the liquefaction process. Changes in any of those variables can affect compressor aerodynamics and operating range. The objective is not simply to design equipment for a single operating point. LNG plants rarely operate continuously at their original design condition. Ambient temperatures change, feed gas composition varies and production requirements shift. That makes operating flexibility increasingly important.
Electrification changes the compressor equation The choice of compressor driver is also evolving. Gas turbines have traditionally played a major role in LNG liquefaction because they can directly drive large refrigerant compressors while allowing the plant to use natural gas as fuel. But interest in electric motordriven compression is increasing, particularly at projects with access to reliable and relatively low-carbon electricity. Electrification can reduce direct plant emissions and allows the compressor to operate independently of gas turbine performance. www.compressortech2.com
LNG
WEBINAR
Nored said electric drives also can provide operational flexibility because motor speed can be adjusted to match process requirements. That flexibility can be particularly valuable when LNG plants operate away from their original design point. But electrification introduces another major consideration: the power grid. An LNG facility requires enormous amounts of energy. Electrifying large refrigerant compressors can place substantial demand on local power infrastructure. Touil said the availability and reliability of electricity must be considered carefully before developers move toward fully electric LNG designs. “You need to look at the grid,” he said. A project cannot simply replace a gas turbine with an electric motor without evaluating where the power will come from and whether the electrical system can reliably support continuous LNG production. For remote projects or facilities in regions with constrained grids, gas turbines may remain the more practical option.
Gas turbines remain important
>
Despite increasing interest in electrification, Nored said gas turbine-driven compression remains an important part of the LNG market. Gas turbines offer high power density and can use natural gas available at the LNG facility. They also allow projects to operate independently of external electrical grids. The technology has continued to evolve as manufacturers improve efficiency and expand operating flexibility. Nored said one consideration is ensuring www.compressortech2.com
the gas turbine and compressor are optimized as a complete train. Changes in ambient conditions can affect gas turbine output, which in turn affects the power available to the refrigerant compressor. That relationship becomes particularly important in hot climates, where gas turbine power output may decline as ambient temperatures increase. Matching the driver and compressor
Mehdy Touil, an LNG specialist widely known in the industry as “the LNG Guy.”
across the expected operating range can help LNG developers maintain production.
Compression throughout the LNG plant While refrigerant compressors often receive the most attention, compression is used throughout an LNG facility.
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LNG
Feed gas booster compressors may be required before pretreatment. Acid gas recovery and regeneration systems also can involve compression. At the center of the plant are the large refrigerant compressors used to circulate propane, mixed refrigerant or other refrigerant streams through the liquefaction process. Once the natural gas is liquefied and moved into storage, boil-off gas compression becomes another critical application. Nored described the liquefaction compressors as the “heart of the plant,” but noted that compressor requirements extend well beyond the main refrigeration cycle. Pretreatment systems, in particular, can vary considerably depending on feed gas composition. That variability is becoming increasingly important as LNG developers seek gas from a broader range of supply sources.
Nitrogen creates new challenges One issue receiving increasing attention is nitrogen content in natural gas. Nored said nitrogen levels in some U.S. gas supplies appear to be increasing. U.S. pipeline tariffs generally limit total diluents — including nitrogen, carbon dioxide and other non-Btu gases — to approximately 3%.
Although most tariff agreements limit total diluents to 3.0%, nitrogen may fluctuate within this range, especially if the percentages of other diluents are low. Historically, nitrogen levels were often below 1%, Nored said. Higher nitrogen concentrations can create challenges in LNG production because nitrogen behaves differently during liquefaction. As LNG is stored, nitrogen can become concentrated in the boil-off gas. That can influence the design of boil-off gas systems and may require developers to consider nitrogen rejection units or alternative ways of managing the gas. Nored said the issue illustrates why compressor and process equipment suppliers increasingly need to understand the complete LNG process rather than focusing only on individual machines. In some cases, nitrogen-rich boil-off gas may be suitable for use as fuel in gas turbines capable of handling high nitrogen concentrations. That gas could then be used to generate power for the LNG process. But the process and compressor train must be optimized so the available power can be effectively transferred to the refrigerant compressors. “It is even more essential for that close partnership with the OEM on the optimization side,” Nored said.
IMAGE: CHENIERE ENERGY
WEBINAR
Boil-off gas becomes an optimization opportunity Boil-off gas has traditionally been viewed as an unavoidable part of LNG storage and handling. Even with heavily insulated tanks, a small amount of LNG continuously vaporizes. Rather than venting that gas, LNG facilities typically compress it and either return it to the liquefaction process or use it as fuel. Touil said boil-off gas management has become increasingly sophisticated as operators seek to maximize LNG production and reduce losses. The composition of boil-off gas can vary considerably, particularly when nitrogen is present. Compressors therefore may need to operate across changing molecular weights and flow conditions. For compressor manufacturers, that
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LNG
WEBINAR
Cheniere’s Sabine Pass LNG export terminal in Louisiana. Refrigerant, feed gas and boil-off gas compressors play critical roles throughout LNG liquefaction facilities.
creates another requirement for operating flexibility. A compressor designed around a narrow operating range may struggle as boil-off gas composition changes. Understanding those variations early in the design process can allow OEMs to select compressor configurations capable of handling expected operating conditions.
Floating LNG adds another layer of complexity The growth of floating LNG also is creating new compressor design considerations. FLNG facilities place liquefaction equipment aboard vessels or floating production units, where space and weight are limited. Unlike land-based LNG plants, equipment must be designed around marine conditions and vessel motion. Touil said FLNG projects also can face unique feed gas conditions because
facilities may be located closer to upstream production. Gas arriving directly from offshore fields can contain higher concentrations of nitrogen, heavier hydrocarbons or other components that must be addressed during pretreatment. That makes the design of the entire liquefaction process highly site specific. For compressor manufacturers, compact equipment footprints and high power density can become particularly important. Reliability also takes on additional significance offshore, where maintenance access and equipment replacement can be considerably more difficult than at a landbased LNG plant.
Reliability remains the ultimate measure Regardless of train size, liquefaction technology or driver selection, Nored and Touil repeatedly returned to one issue: reliability. LNG facilities are designed to operate for decades. A compressor selected during project development may remain in service for 20 or 30 years, often under operating conditions that change substantially over the life of the plant. That makes equipment flexibility increasingly valuable.
Feed gas sources may change. Nitrogen concentrations may increase. Ambient conditions can shift, and operators may seek to increase production beyond the plant’s original design capacity. Compressors and drivers capable of accommodating those changes can give operators more options over the life of the facility. LNG projects will continue to evolve as developers push for faster speed to market while responding to environmental requirements and site-specific challenges. For compressor manufacturers, that evolution will require flexible, reliable and high-performing equipment capable of supporting the range of compression services across an LNG plant. The equipment may be selected during the development phase, but its performance will be measured over decades of operation. For Nored and Touil, that makes early collaboration among developers, operators, process designers and equipment suppliers increasingly important as the next generation of LNG projects moves forward. CT2
Scan here to view the full webinar or visit our website www.compressortech2.com/video
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OCTOBER2025 DECEMBER
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2026 SEPTEMBER Carbon Capture Canada Sept. 15-17 Edmonton, Alberta Carbonexpocanada.com
RNG Works Sept. 15-17 Milwaukee, Wisconsin Rngcoalition.com/rng-works GPA MIDSTREAM Sept. 20-23 San Antonio, Texas www.gpamidstream.org
TPS 2026 Sept. 22-24 Houston, Texas Tps.tamu.edu
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15TH EFRC CONFERENCE Sept. 28-30 The Hague, Netherlands www.recip.org
For a complete listing of upcoming events, please scan the QR code or visit our website: www.compressortech2.com/events GAS LINES
COMPANY NEWS
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MONITORING GOVERNMENT SPEED ACT UPDATE
A KHL Group publication
BRAZIL DOUBLES LNG
CORNERSTONES
OF COMPRESSION www.compressortech2.com JANUARY 2026
CORNERSTONES COROLLARY: EVOLUTION OF PIPELINES AND COMPRESSOR STATIONS The Cornerstones of Compression series has highlighted many significant products over more than 160 years of continuous progress. This is the sixth of seven (formerly six) Cornerstones of Compression corollary articles that provide a look the evolution of natural gas pipelines and compressor stations. By Norm Shade
Xxxxxxxxxxxxxxxxxx
Readership survey MANUFACTURER
Allis Chalmers Bessemer Blaisdell Bury Carter Clark Climax Cooper Hamilton Ingersoll-Rand Jacobson LaidlawDunn-Gordon National Transit Nordberg Rathburn Jones Reeves Strait Snow Waukesha Westinghouse Worthington Totals
HORIZONTAL GAS ENGINE
VERTICAL GAS ENGINE
HORIZONTAL GAS ENGINECOMPRESSOR
HORIZONTAL BELT-DRIVEN COMPRESSOR
HORIZONTAL STEAM ENGINECOMPRESSOR
STEAM TURBINE
TOTAL UNITS
0 62 0 0 0 0 0 0 0 0 1
0 0 0 0 0 0 2 0 0 0 0
1 20 0 0 0 70 0 11 0 0 0
0 12 2 1 4 0 0 0 0 52 0
0 0 0 0 0 0 0 0 6 3 0
0 0 0 0 0 0 0 0 0 0 0
1 94 2 1 4 70 2 11 6 55 1
Xxxxxxxxxxxxxxxxxxxx
GAS LINES
www.compressortech2.com
0
0
1
0
0
0 0 2 3 0
76 0 0 0 1
0 0 0 0 0
9 1 0 0 0 0 0 0 7 26
0 0 0 0 0 0 0 1 0 1
0 19 5 CORNERSTONES 6 0 0
EVOLUTION OF 0 5 19 0 0 8 PIPELINES 18 217 85
(formerly six) Cornerstones of Compression corollary articles that provide a look the evolution of natural gas pipelines and compressor stations. By Norm Shade
Xxxxxxxxxxxxxxxxxx
EURO REPORT TAP EXPANDS CAPACITY
CORNERSTONES
OF COMPRESSION
over more than 160 years of continuous progress. This is the sixth of seven
HOERBIGER’S 1 AREK 86 DYRDOL
1 2 3 1 24 6 25 15 411
SPEED ACT UPDATE
The Cornerstones of Compression series has highlighted many significant products
EXECUTIVE Q&A
R
>
ecent issues of Cornerstones of Compression articles described the gas engines and compressors at sixteen early compressor stations of the Ohio Fuel Gas Company, which was organized in 1902. The equipment covered a wide range of ratings and was provided by a number of manufacturers primarily from Ohio and western Pennsylvania, which is where oil and gas production boomed at the time.
JANAURY 2026 | COMPRESSORTECH2 | 49
TABLE
The largest early natural gas pipeline company, Hope Natural Gas Company, was organized in 1899, operating in West Virginia and western Pennsylvania. Among the archives at the Coolspring Power Museum is a 1930 notebook that documents the history and the engine and compressor inventory of each of the 86 compressor stations that made up the Hope Natural Gas Company and their subsidiaries Reserve Gas Company and Hope Construction & Refining Company
1 Hope Natural Gas Co. Engines and Compressors By Manufacturer.
up to that time. The stations included gas gathering and boosting, natural gasoline production, and gas transmission services, ranging in size from 50 to 22,025 hp (37 to 16,424 kW). There were 411 units in total, and the variation in equipment was impressive. The majority of the engines and compressors were produced by companies located in Pennsylvania or New York, which were prevalent in early air compressor and gas engine and compressor manufacture. The rest came from companies in the industrial midwestern states of Ohio and Wisconsin.
Readership survey MANUFACTURER
GAS LINES
COMPANY NEWS
BRAZIL DOUBLES LNG
GREENE TWEED BENCHMARK
Allis Chalmers Bessemer Blaisdell Bury Carter Clark Climax Cooper
HORIZONTAL GAS ENGINE
0 62 0 0 0 0 0 0 0 0 1
VERTICAL GAS ENGINE
HORIZONTAL GAS ENGINECOMPRESSOR
HORIZONTAL BELT-DRIVEN COMPRESSOR
0 0 0 0 0 0 2 0 0 0 0
1 20 0 0 0 70 0 11 0 0 0
0 12 2 1 4 0 0 0 0 52 0
HORIZONTAL STEAM ENGINECOMPRESSOR
STEAM TURBINE
TOTAL UNITS
0 0 0 0 0 0 0 0 6 3 0
0 0 0 0 0 0 0 0 0 0 0
0
0
1
0
0
1
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0 0 0 0 0
9 1 0 0 0 0 0 0 7 26
0 0 0 0 0 0 0 1 0 1
86 1 2 3 1 24 6 25 15 411
1 94 2 1 4 70 2 11
Xxxxxxxxxxxxxxxxxxxx
NOW!
The entire inventory by manufacturer and type of equipment is shown in Table 1. The earliest machines were 85 belt-driven horizontal compressors. The majority, 52, were manufactured by Ingersoll-Rand, which adapted their extensive line of air compressors for natural gas and oil field
Demand booming, challenges remain
MONITORING GOVERNMENT SPEED ACT UPDATE
Hamilton REGAL REXNORD Ingersoll-Rand Jacobson RECERTIFICATION LaidlawEXPANSION Dunn-Gordon
National Transit Nordberg Rathburn Jones Reeves Strait Snow Waukesha Westinghouse Worthington Totals
CORNERSTONES
OF COMPRESSION www.compressortech2.com JANUARY 2026
0 1 0 0 0 0 0 0 0 0 64
0 19 5 CORNERSTONES 6 0 0
EVOLUTION OF 0 5 19 0 0 8 PIPELINES 18 217 85
6 applications. Bessemer manufactured 12 EXECUTIVE Q&A 55 of these units, with the rest supplied by six 1
HOERBIGER’S other companies as shown in Table 1. Most of these horizontal compressors AREK were belt-driven by 62 Bessemer horizontal DYRDOL gas engines. In addition, 18 were belt-driven by vertical gas engines manufactured by Waukesha, Westinghouse and several other companies. Interestingly, one large IngersollRand horizontal reciprocating compressor was belt-driven by a Westinghouse steam turbine. As indicated in Table 1, over half of Hope’s fleet were horizontal gas engine
www.compressortech2.com
(formerly six) Cornerstones of Compression corollary articles that provide a look the evolution of natural gas pipelines and compressor stations. By Norm Shade
Xxxxxxxxxxxxxxxxxx R
ecent issues of Cornerstones of Compression articles described the gas engines and compressors at sixteen early compressor stations of the Ohio Fuel Gas Company, which was organized in 1902. The equipment covered a wide range of ratings and was provided by a number of manufacturers primarily from Ohio and western Pennsylvania, which is where oil and gas production boomed at the time. TABLE
The largest early natural gas pipeline company, Hope Natural Gas Company, was organized in 1899, operating in West Virginia and western Pennsylvania. Among the archives at the Coolspring Power Museum is a 1930 notebook that documents the history and the engine and compressor inventory of each of the 86 compressor stations that made up the Hope Natural Gas Company and their subsidiaries Reserve Gas Company and Hope Construction & Refining Company
1 Hope Natural Gas Co. Engines and Compressors By Manufacturer.
up to that time. The stations included gas gathering and boosting, natural gasoline production, and gas transmission services, ranging in size from 50 to 22,025 hp (37 to 16,424 kW). There were 411 units in total, and the variation in equipment was impressive. The majority of the engines and compressors were produced by companies located in Pennsylvania or New York, which were prevalent in early air compressor and gas engine and compressor manufacture. The rest came from companies in the industrial midwestern states of Ohio and Wisconsin.
Readership survey MANUFACTURER
Allis Chalmers Bessemer Blaisdell Bury Carter Clark Climax Cooper Hamilton Ingersoll-Rand Jacobson LaidlawDunn-Gordon National Transit Nordberg Rathburn Jones Reeves Strait Snow Waukesha Westinghouse Worthington Totals
HORIZONTAL GAS ENGINE
VERTICAL GAS ENGINE
HORIZONTAL GAS ENGINECOMPRESSOR
HORIZONTAL BELT-DRIVEN COMPRESSOR
HORIZONTAL STEAM ENGINECOMPRESSOR
STEAM TURBINE
TOTAL UNITS
0 62 0 0 0 0 0 0 0 0 1
0 0 0 0 0 0 2 0 0 0 0
1 20 0 0 0 70 0 11 0 0 0
0 12 2 1 4 0 0 0 0 52 0
0 0 0 0 0 0 0 0 6 3 0
0 0 0 0 0 0 0 0 0 0 0
1 94 2 1 4 70 2 11 6 55 1
Xxxxxxxxxxxxxxxxxxxx
NOW!
The entire inventory by manufacturer and type of equipment is shown in Table 1. The earliest machines were 85 belt-driven horizontal compressors. The majority, 52, were manufactured by Ingersoll-Rand, which adapted their extensive line of air compressors for natural gas and oil field applications. Bessemer manufactured 12 of these units, with the rest supplied by six other companies as shown in Table 1. Most of these horizontal compressors were belt-driven by 62 Bessemer horizontal gas engines. In addition, 18 were belt-driven by vertical gas engines manufactured by Waukesha, Westinghouse and several other companies. Interestingly, one large IngersollRand horizontal reciprocating compressor was belt-driven by a Westinghouse steam turbine. As indicated in Table 1, over half of Hope’s fleet were horizontal gas engine
Demand booming, challenges remain REGAL REXNORD RECERTIFICATION EXPANSION
0 1 0 0 0 0 0 0 0 0 64
www.compressortech2.com
HOERBIGER’S AREK DYRDOL
0
1
0
0
1
0 0 2 3 0
76 0 0 0 1
0 0 0 0 0
9 1 0 0 0 0 0 0 7 26
0 0 0 0 0 0 0 1 0 1
86 1 2 3 1 24 6 25 15 411
EURO REPORT TAP EXPANDS CAPACITY
JANAURY 2026 | COMPRESSORTECH2 | 49
>
• Pressures to 6000psi, temperatures to 500°F. • Short, straight flow path to minimize channel resonance, maximize accuracy.
EXECUTIVE Q&A
0
0 19 5 CORNERSTONES 6 0 0
EVOLUTION OF 0 5 19 0 0 8 PIPELINES 18 217 85
KIENE Indicator Valves for Compressor Analysis
EURO REPORT TAP EXPANDS CAPACITY
CORNERSTONES COROLLARY: EVOLUTION OF PIPELINES AND COMPRESSOR STATIONS The Cornerstones of Compression series has highlighted many significant products over more than 160 years of continuous progress. This is the sixth of seven
SUBSCRIBE
0 1 0 0 0 0 0 0 0 0 64
MONITORING GOVERNMENT
CORNERSTONES COROLLARY: EVOLUTION OF PIPELINES AND COMPRESSOR STATIONS
A KHL Group publication
REGAL REXNORD
GREENE TWEED BENCHMARK
www.compressortech2.com JANUARY 2026
Demand booming, challenges remain RECERTIFICATION EXPANSION
COMPANY NEWS
BRAZIL DOUBLES LNG
NOW!
The entire inventory by manufacturer and type of equipment is shown in Table 1. The earliest machines were 85 belt-driven horizontal compressors. The majority, 52, were manufactured by Ingersoll-Rand, which adapted their extensive line of air compressors for natural gas and oil field applications. Bessemer manufactured 12 of these units, with the rest supplied by six other companies as shown in Table 1. Most of these horizontal compressors were belt-driven by 62 Bessemer horizontal gas engines. In addition, 18 were belt-driven by vertical gas engines manufactured by Waukesha, Westinghouse and several other companies. Interestingly, one large IngersollRand horizontal reciprocating compressor was belt-driven by a Westinghouse steam turbine. As indicated in Table 1, over half of Hope’s fleet were horizontal gas engine
SUBSCRIBE
1 Hope Natural Gas Co. Engines and Compressors By Manufacturer.
up to that time. The stations included gas gathering and boosting, natural gasoline production, and gas transmission services, ranging in size from 50 to 22,025 hp (37 to 16,424 kW). There were 411 units in total, and the variation in equipment was impressive. The majority of the engines and compressors were produced by companies located in Pennsylvania or New York, which were prevalent in early air compressor and gas engine and compressor manufacture. The rest came from companies in the industrial midwestern states of Ohio and Wisconsin.
A KHL Group publication
TABLE
The largest early natural gas pipeline company, Hope Natural Gas Company, was organized in 1899, operating in West Virginia and western Pennsylvania. Among the archives at the Coolspring Power Museum is a 1930 notebook that documents the history and the engine and compressor inventory of each of the 86 compressor stations that made up the Hope Natural Gas Company and their subsidiaries Reserve Gas Company and Hope Construction & Refining Company
SUBSCRIBE
R
ecent issues of Cornerstones of Compression articles described the gas engines and compressors at sixteen early compressor stations of the Ohio Fuel Gas Company, which was organized in 1902. The equipment covered a wide range of ratings and was provided by a number of manufacturers primarily from Ohio and western Pennsylvania, which is where oil and gas production boomed at the time.
>
JANAURY 2026 | COMPRESSORTECH2 | 49
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CROSSHEAD, PIN BEARING
Reiner Schulz and Roger Keller Research and Development Burckhardt Compression AG Winterthur Switzerland
Abstract The crosshead is a critical component of compressors, playing a significant role in ensuring overall reliability. One of the key factors influencing this reliability is the lubricant film thickness, avoiding mixed friction by maintaining a sufficient thickness is essential for minimizing wear and enhancing the longevity of the
compressor components. The investigation extends to the pin bearing, another essential component in compressor design. Pin bearing performance is heavily influenced by rod reversal, which is crucial for proper operation. However, in special cases, such as single-acting compressors or compressors with specific cylinder designs, rod reversal can be minimal.
Crosshead and pin bearing in 1
Introduction
Hydrodynamic bearings are integral components in compressor crank gears, providing a low-wear, space-efficient, and energy-saving connection between moving parts such as the connecting rod and crankshaft (small and big end bearings) or the crosshead and frame. These bearings function through a lubricating film generated by the relative motion between the bearing and the shaft, which supports the load and prevents direct surface contact, thereby minimizing wear and friction. Given the escalating demands for higher load capacities and extended service life
THE AUTHORS
EDITOR’S NOTE: This paper was first presented at the 14th EFRC Conference, Oct. 14-16, 2025, in Hamburg, Germany.
ROGER KELLER holds a master's degree in mechanical engineering with a specialization in Computer-Aided Engineering. He works as a Simulation Expert in R&D at Burckhardt Compression, Switzerland. His work focuses on the numerical simulation of reciprocating compressors, with emphasis on CFD, tribology, and coupled multiphysics modeling
DR.-ING. REINER SCHULZ, Research and Development, Burckhardt Compression AG, Winterthur, Switzerland. Schulz is the named inventor or co-inventor on numerous Burckhardt patents.
62 | COMPRESSORTECH2 | AUGUST-SEPTEMBER 2026
in compressors, the design of hydrodynamic bearings must address increasingly complex load scenarios and operating conditions. Historical data indicates that inadequate bearing design can result in substantial damage and associated costs. Therefore, it is imperative to consider the bearing itself and the entire system of bearings and adjacent components to prevent premature failures and mitigate potential damages and costs.
2
Methodology
Various aspects of journal bearing simulation in compressors have already been described1,2. Since the focus of this paper is on practical applications, the methodology will only be briefly explained. The bearings with the neighboring components are simulated as a mechanical multi-body system (MBS), where the bodies are usually elastic and are connected either via massless kinematic connecting elements or via force (spring/ damper) elements or (predominantly hydrodynamic) bearings, using a commercial software3. In a precalculation, the total number of degrees of freedom of the structure is reduced while retaining accurate description of the dynamic behaviour4, and a response function is constructed which gives the elastic response of the structure due to a load in the contact
1
FIGURE Traditional design of pin bearing with multiple longitudinal lubrication grooves.
zone with the fluid. If the lubricating film is simulated by solving the Reynolds equation, considering the deformations of the neighboring components, this is referred to as elastohydrodynamic analysis (EHD). In EHD simulations oil viscosity is assumed to be constant. In all simulations described in this paper, cavitation is considered using a transient algorithm assuring mass-conservation in the fluid film6, thus avoiding negative oil pressures that could otherwise arise due to the Reynolds equation, but which are unrealistic. If the temperature distribution is considered in addition to the points described under EHD, this leads to TEHD. The problem of the different time scales (rapid processes in the lubrication film and gradual temperature changes in the neighboring bodies) is solved using a special iteration process, coupling two time scales. With the known temperature distribution in the oil film, its viscosity is calculated as a distribution. This method is the most accurate and suitable for assessing cooling concepts; however, it is associated with corresponding effort. For the EHD and TEHD simulations, realistic boundary conditions such as www.compressortech2.com
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Three distinct pin bearing concepts are introduced, particularly for scenarios where rod reversal is short or absent, e.g. single acting cylinders as diaphragm compressors employing plain pin bearings. In applications with limited rod reversal, a special contour is proposed to support oil replenishment. A small, controlled supply of oil under increased pressure is suggested as a viable
solution even for instances where no rod reversal occurs. Additionally, an innovative approach using two alternately loaded and unloaded bearings is discussed. This study offers valuable insights into improving compressor design, with a particular focus on optimizing lubrication strategies for both crosshead and pin bearings.
g investigations time-varying oil pressure, heat transfer coefficients of components (possibly with cooling), pressure distribution on pistons, etc., are required; these are derived using computational fluid dynamics (CFD). CFD is also used better to understand better mixing processes in lubrication grooves or films because the possibilities of EHD or TEHD are limited due to the Reynolds equation.
3
Pin bearing investigations
3.1 STANDARD PIN BEARING The traditional design for operation with marginally little rod reversal is the bearing with multiple lubrication grooves (Figure 1) The angular spacing of the grooves corresponds approximately to the swing angle of the connecting rod. A higher spacing is not feasible because oil is dragged into the lubrication gap due to adhesion to the moving wall, and a smaller spacing results in a reduced load-supporting area6. The quantity of oil that can be conveyed by wall adhesion is naturally minimal. The grooves can also be helically wound. The grooves can have small bleed openings at the ends, creating an oil flow. This flow ensures that the temperature of the oil in the groove remains lower than without these openings, as the oil, which is conveyed back from the gap into the lubrication groove that is already heated by friction, is removed more strongly than without this flow. Lower temperatures are associated with higher viscosity, which positively affects the load-carrying capacity of this type of bearing. The oil pressure in the www.compressortech2.com
lubrication grooves is by no means constant. Depending on the design of the oil supply, effects from accelerations, throttling, and pumping action of individual components may result, so the oil pressure effective in a lubrication groove may have no significant relation to the pressure at the pump. Furthermore, it is crucial how the bearing's oil demand and the pressure curve coincide over time. Although a simple increase in bearing clearance increases the flow rate, it has the known disadvantages that the load carrying capacity decreases, the maximum pressure increases and a smaller minimum lubricating film thickness hmin occurs than with a smaller bearing clearance. The oil's viscosity has a significant impact. Since viscosity is highly dependent on temperature, simulations taking into account temperature will be performed, and tests will be conducted. A test bench setup is shown in Figure 2. Figure 3 shows exemplary measurements
FIGURE
2 Test bench for pin bearing tests.
of the lubrication film thickness at a certain location and at a point of time immediately before the load reverses, taken by eddy current sensors in a multiple groove type bearing for different oils. The oil and its flow (resulting temperature, respectively) significantly impact the minimum film thickness. The bearing with multiple lubrication grooves has the advantage of being relatively insensitive to load variation. 3.2 CONTOURED BEARING An internal contour, i.e. a deviation from the cylindrical shape such as an elongated hole, can keep the bearing clearance in the active area small while achieving a large gap height in the lifted state. A sufficient gap height is a prerequisite for supplying the lubrication film with enough oil at the given pressure in the time available, as flow depends on the height at the third power. Suppose there is a minimum amount of rod reversal in the sense of a sufficiently
3
FIGURE Test results showing the impact of oil quality on film thickness, measured raw data (left) and with zero-point correction (right).
AUGUST-SEPTEMBER 2026 | COMPRESSORTECH2 | 63
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large opposing force (or a force impulse). In that case, the bearing changes the contact surface reliably. But if the duration is too short to allow sufficient renewal of the lubricating film in a conventional bearing, it is advisable to use a bearing with an internal contour. For a typical application with a rod reversal of 80° crank angle duration and a force ratio of 30%, the contoured and standard bearing designs were compared by simulations in which the lubricating film is simulated, considering cavitation and the deformations of all components involved (EHD simulation). Figure 4 gives an impression of the two bearing types. The bearing with multiple lubrication grooves has much higher peak pressures and smaller lubricant film thicknesses. Figures 5 and 6 summarize the most important simulation results. As can be seen from Figure 5, the bearing with inner contour offers much higher film thickness hmin, while in the multiple groove type bearing, mixed friction occurs at times (bump between 180 and 240 deg. CA in Figure 6). Mixed friction is characterized by the fact that the roughness peaks of the components penetrate each other. The roughness data must be specified based on empirical data. In the simulations, mixed friction begins at lubricant film thicknesses below approximately 2 microns. Thicknesses of more than three microns should enable fully hydrodynamic operation; however, this depends on surface qualities.
5
4
FIGURE Typical pressure distribution in bearing with multiple lubrication grooves (unfavorable division of the pressure distribution, left).
Higher values increase safety in the presence of contaminants or particles. The concept of bearing with an inner contour fails in cases when the gap on the load-carrying side does not open sufficiently. Potential changes in the operating conditions of the plant belonging to the compressor may change rod reversal and must be considered. 3.3 PRESSURE SUPPORTED PIN BEARING The injection of a small amount of high-pressure oil allows for permanent hydrodynamic operation without any rod reversal. This concept has become established in large marine (two-stroke diesel) engines and has completely replaced the bearing with multiple grooves for decades. High-pressure oil is also used in turbines as jacking oil, usually a starting aid. The pressure range varies depending on the application, from approximately 30 bar for large marine engines to several hundred bar for turbines. The application in a reciprocating compressor is more
FIGURE Comparison of bearing with multiple grooves and inner contour: simulated minimum lubrication film thickness.
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comparable to a piston engine, as in both cases, the load is transient, and the oil is introduced into the lubricating film at a favorable time. The lubricating film is therefore replenished at low load to carry high load peaks by squeeze oil. Therefore, it is a hydrodynamic operation supported by oil pressure, in contrast to a hydrostatic bearing, which would also be possible. Oil is usually supplied from the outside via knee levers or telescopic pipes. Still, pumps have also been used that are integrated into the crosshead and utilize the movement of the connecting rod7. In diaphragm compressors, pressurized oil may be tapped off through the piston under certain operating conditions, and a small spring-loaded piston accumulator may help lubricate a hydrodynamic pin bearing. For a load curve without rod reversal, the relationship between minimum lubricating film thickness and oil pressure was investigated for various designs of lubrication grooves (Figures 7 and 8). As can be seen from the diagrams, the lubrication film thickness is dependent on oil pressure. If a certain lubrification film thickness is required to avoid direct contact of the parts and to have a safety margin for particles, then a minimum oil pressure is required for each design. The squeezing and distortion of the oil film cause dissipation, and the additional external pump used in this type of bearing has limited efficiency; for illustration, an
6
FIGURE Comparison of bearings with multiple grooves and inner contour: simulated friction losses.
AUGUST-SEPTEMBER 2026 | COMPRESSORTECH2 | 65
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FIGURE
7 Minimum lubrication film thickness dependent on oil pressure.
efficiency of 50% was assumed to calculate the total dissipation, as shown in Figure 9. The optimum shape of the high-pressure oil lubrication groove depends on the film thickness. If a minimum lubrication film thickness of, for example, 8 microns is aimed at, the design with four lubrication pockets offers the lowest total dissipation. For a film thickness of 6 microns, the design with two longitudinal grooves is best, and for 5 microns, a single longitudinal groove of medium size is best (Figure 10). However, the dissipation of this type of bearing, including the external pump, is lower than that of a multi-groove bearing operating in mixed friction mode. As an additional criterion for evaluating groove designs, the replacement or renewal of the oil in the lubricating film was investigated in more detail. The deformations and oil flows of the oil
FIGURE
8 Minimum lubrication film thickness dependent on oil pressure over a cycle.
film are transferred from the MBS to a CFD program, whereby the velocity distribution and the gap height distribution are retained. The gap height is increased proportionally for practical reasons, but this does not affect the results because pressure is irrelevant to this investigation. Passive scalars are applied to each pressure boundary for the duration of one cycle with a concentration of 100% during the cycle and 0% for the remaining time. From the transport of these scalars, it is possible to trace where the oil in the lubricating film comes from, from the oil supply, the outer edge, or an additional highpressure supply. As it is not always clear whether oil or air/gas is present at the outer edge, this can be an important point. The concentrations of the scalars transported and mixed over several cycles give a distribution of the residence time of the oil,
9 Dissipation including external pump dependent on oil pressure.
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FIGURE
FIGURE
determined by multiplying the concentration by the number of cycles elapsed since the scalar boundary condition was set and summing the resulting concentration. Figure 11 is an example of the resulting distribution. The scale must be interpreted in complete cycles, i.e., the areas in dark red are filled with oil more than four cycles old. In this way, it is possible to identify areas in a bearing where sufficient oil is present but rarely exchanged. Hence, particle removal is poorly supported. It is difficult, if not
11
FIGURE Plot showing the distribution of oil age (in terms of cycles).
10 Film thickness dependent on total friction losses. AUGUST-SEPTEMBER 2026 | COMPRESSORTECH2 | 67
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CROSSHEAD, PIN BEARING
FIGURE
12
FIGURE Illustration of the functional principle: Alternating loading of two bearing segments
impossible, to assess such effects based on velocity fields alone 3.4 KINEMATIC REVERSAL MECHANISM An alternative approach to facilitating the hydrodynamic operation of the pin bearing in circumstances where rod reversal is either minimal or entirely absent involves alternating the load distribution between two distinct bearing segments. This creates favorable conditions for the renewal of the lubricating film8. Figure 12 shows the underlying principle. It should only be interpreted as a basic schematic representation, in which the proportions are intentionally distorted for illustrative purposes. In the provided example, a temporal constant load is split between the left and right bearing segments (small arrows). The connecting rod's oscillatory motion cyclically imposes and relieves the load on each bearing segment, with the gap being determined by the kinematic design. Thanks to the significant opening of the gap and the defined duration, the lubricant can be replenished even under
14 Min lubrication film thickness in the bearing segments.
typically low oil pressures (the open gap is highlighted in blue). The maximum eccentricity E is in the range of 5/1000 of the diameter D; thus, an actual bearing implementation appears quite different from Figure 12. Figure 13 presents an experimental prototype with an assembled pin, although designs using single-piece components are also feasible. This design underwent extensive simulation analysis. Specifically, scenarios involving constant load and a load profile with negligible rod reversal were evaluated. Designs featuring varied bearing clearances and both contoured and non-contoured configurations were compared. Results indicated that lubricant film thicknesses exceeding5 micrometers can be sustained. For illustration, Figure 14 compares the hmin value across different crank angles for the two configurations: one featuring large bearing clearance without a contour
15
FIGURE Model of the frame, standard crosshead with pin bearing, connecting rod and piston rod .
and another exhibiting standard bearing clearance with a contour. The investigations were limited to a given geometry; only the clearance and contours varied. However, further optimization options exist, e.g., distributing the available installation space on the bearing surfaces differently, etc. This bearing design has the disadvantage that the effective bearing area is smaller than the variants described above, as it has to be divided. In most cases, this disadvantage is more than compensated by the improved oil supply. It seems possible to create a bearing on this basis, for example, for a retrofit.
4
Crosshead investigations
FIGURE Cross-sectional view of an experimental pin (left) and transparent model showing bearing surfaces (right): (a): dowel pin holes, (b): holes for clamping screws, (c): holes for connection to test rig, (d): radial bores for oil.
4.1 STANDARD CROSSHEAD DESIGN 4.1.1 INVESTIGATIONS INCLUDING FRAME The behavior of the standard crosshead was investigated in detail, the model comprises the crosshead body with the piston rod, the connecting rod, and the frame (Figure 15). The frame is fixed at the bottom. The piston rod is radially fixed at its top, where the gas and mass forces from the piston are applied. A circular motion is applied to the
68 | COMPRESSORTECH2 | AUGUST-SEPTEMBER 2026
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13
TECH CORNER
CROSSHEAD, PIN BEARING
big end side of the connecting rod. Unlike the pin bearing, where part load cases with valve unloading are more critical, the double-acting case for the crosshead creates the lowest minimum oil film thickness. In these scenarios, due to the direction change of the connecting rod, the lateral force on the crosshead acts predominantly in the same direction, with only brief reversals. Unlike the pin bearing, where part load cases with valve unloading are more critical, the double-acting case for the crosshead creates the lowest minimum oil film thickness. In these scenarios, due to the direction change of the connecting rod, the lateral force on the crosshead acts predominantly in the same direction, with only brief reversals. In an EHD analysis, the cycle averaged minimum oil film thickness hmin is highest at the center of the sliding surface and lowest along the edges (Figure 18, right). This distribution is attributed to the structural deformation of the crosshead during maximal tension and compression, as shown in Figure 16. During maximum compression or tension, the sliding surface's upper or lower outer edges deform outwards against the crosshead bore of the frame. The hydrodynamic squeeze film effect near the edge of the sliding surface has little impact due to oil escaping quickly. This demonstrates that the minimum oil film thickness is influenced not only by hydrodynamic effects but also largely by local structural deformations of the crosshead body and its counterpart.
16
FIGURE Deformation of Crosshead during maximum compression (CA~170°) and maximum tension (CA~320°). Scaling factor 2000.
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FIGURE
18 Cycle averaged minimum oil film thickness for the loaded side of the crosshead, with (TEHD, left) and without thermal effects (EHD, right).
17
FIGURE Temperature distribution and resulting thermal deformations, standard crosshead design.
4.1.2 INVESTIGATIONS INCLUDING THERMAL EFFECTS In an EHD Analysis, a constant oil viscosity is assumed, but the viscosity of typical lubricating oils is strongly temperature dependent. Additionally, the frictional heat generated within the lubricating oil film increases the temperature of adjacent bodies, and the resulting thermal expansion influences the film thickness distribution. These effects are considered in a TEHD Analysis, where the temperatures, resulting viscosity distribution, thermal expansions, and deformations are also part of the solution. The crosshead's temperature distribution is highly asymmetric due to the load acting primarily on one side, leading to asymmetric thermal deformation. Since most frictional
heat is generated at the center of the sliding surface, the resulting temperature distribution causes a spherical deformation of the standard crosshead (Figure 17), concentrating the zone of highest loads at the center. The magnitude of the crosshead's thermal deformation is significantly greater than the purely structural deformation caused by external forces. Therefore, no distinction is necessary between the crosshead's maximum tension and maximum compression states. The deformation defining the sliding surface's potential contact distribution is primarily due to thermal expansion. Additionally, the spherical deformation shape prevents edge loading in the heated-up state; however, this is not the case during startup. 4.1.3 COMPARISON EHD - TEHD Comparing the minimum oil film thickness distribution of an EHD Analysis to the corresponding TEHD analysis shows a complete reversal of the pattern (Figure 18). When only structural deformations of the crosshead are considered (EHD), the lowest film thicknesses occur at the outer edges of the sliding surface. Thermal expansion effects (TEHD) cause a spherical deformation of the crosshead, shifting the zone of highest loading and lowest film thicknesses to the center. This underscores the importance of thermal AUGUST-SEPTEMBER 2026 | COMPRESSORTECH2 | 69
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FIGURE
20 Simple simulation model: lubrification film thickness.
FIGURE
22 Min. lubrication film thickness for different load cases.
21
FIGURE
23 Forces perpendicular to guide shoes and resultant force.
FIGURE Min. lubrication film thickness for three different positions of the pivot point, load case idle.
effects in understanding contact patterns of crossheads and highlights the critical role of cooling and thermal management for highly loaded crossheads. 4.2 CROSSHEAD DESIGN FOR EXPERIMENTS A crosshead design for experimental investigations aiming at easy manufacturing from billet material is shown in Figure 19. The three-part construction consists of a fork, to which the piston rod is attached, which provides the connection to the pin, and two guide shoes machined from billet material. In the simplest case, as shown, these can be laid on, but they can also be bolted on, or a connection can use a flexible intermediate link. As can be seen, the pin is fixed by bolts, as this allows for more compact dimensions or, given the bore size, a larger pin diameter. This also has the advantage of making 70 | COMPRESSORTECH2 | AUGUST-SEPTEMBER 2026
the construction stiffer and reducing deformations. However, designs with a through-hole pin are also possible. To clarify whether the concept of tilting guide shoes, known from tilting pad bearings, can be transferred to the crosshead, the design shown in Figure 19 was examined in more detail. The fact that
19
FIGURE Three-piece crosshead design for experiments (left) and EHD model (right).
a one-piece casting with appropriately designed flexibility between the fork and guides is desirable for a series production version is irrelevant. As a first step, a simple model consisting of a segment of the liner, which was modeled as a rigid body, and a guide shoe of the crosshead was used for simulations. In the simplest case, the guide shoe is moved back and forth in a sinusoidal manner and subjected to a constant force, but other boundary conditions are also possible, of course. With such a straightforward model, guide shoe and lubrication groove designs and contours can be quickly compared. For example, Figure 20 shows the effect of changing the contour (i.e., changing the wedges at the ends, etc.) under a constant load of 5000 N. After a few cycles, it is visible that variant 1 leads to considerable mixed friction. www.compressortech2.com
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After a restart with a different contour, the shoe floats up with a lubricating film thickness of 0.7 mm. However, this is only possible because in the model oil flows unlimitedly, a more realistic pressure-volume flow curve should have been used. As the example shows, it is necessary to be careful in choosing boundary conditions and interpreting the results. However, to isolate the various influences on the running behavior of a crosshead design, such models of individual components are essential. In the second step, a model was created, as shown in Figure 19 (right). The crankcase is reduced to the bearing surfaces and the guide bearing. Deformations of the bearings, which are mainly caused by thermal distortion, are known from FE models and can be taken into account by superimposing them as a contour. First, a variation of the pivot location of the guide shoe bearing was carried out for the idle load case (i.e. only inertial forces), whereby thermal distortion was not considered. The guide shoes are mounted coaxially with the pin (Figure 19), but this is purely for practical reasons and not necessarily optimal. This pivot point was shifted by 20 mm in both directions (the pin diameter is 130 mm). The interaction of mass and pressure forces results in minimal distortion and tilting movement, which affects the lubrication film. As shown in Figure 21, the minimum film thickness exceeds 30
FIGURE
24
FIGURE Crosshead designs for use without guide bearing, standard (left), variants 1 (middle) and 2 (right).
micrometers. A shift in the pivot point has a significant impact on the film thickness. Increasing the distance between the bearing surface and the pivot point results in a stronger tilting movement reflected in a smaller minimum film thickness. The optimum has already been exceeded if the pivot point is coaxial with the pin. Furthermore, different load cases were compared, taking into account the liner's deformation. These were taken from FE simulations and transferred to the liner. As illustrated in Figure 22, the value hmin remains in the range of 25 microns or above, even under a typical load profile of a doubleacting cylinder, leading to a high safety level against direct contact. Another interesting aspect of this design is that the force acting on both sides of the crosshead fluctuates over a cycle of around 15 kN but is always greater than 12 kN on both sides. There is always a significant pressure, whereby the parts are tensioned, and a high film thickness is maintained. The amount of the resultant force is in the range of 10 kN.
25 Min. film thickness, Crosshead variants 1 and 2.
72 | COMPRESSORTECH2 | AUGUST-SEPTEMBER 2026
FIGURE
4.3 CROSSHEAD DESIGNS REPLACING GUIDE BEARINGS In addition to compressor designs in which the crosshead and piston guide the piston rod, designs of vertical compressors use a special guide bearing. In the former case, wear of the guide elements on the piston can lead to an angular deviation between the cylinder bore in the frame and the piston rod, so it is advantageous if the crosshead is not sensitive to this. In the second case, if no guide bearing is used on the piston rod, e.g., small compressors, the guide bearing's task must be taken over by the crosshead, which is a slightly different task. Crossheads for this task are shown in Figure 24. The crosshead on the left corresponds to a standard version; next to it are variants one and two, which will be examined in more detail below. Figure 25 plots the minimum film thickness from the start of the simulation. The start is intentionally eccentric, so the minimum lubricant film thickness is initially tiny. First, both variants were simulated with load case idle (only inertia forces). It turned out that variant 2 is better, so only one curve is available for variant 1. At nominal load, a lubricant film thickness in the range of 12 microns or more can be expected, which is considerably more than with the standard version. The radial deflection of the end of the piston rod with the piston is shown in Figure 26.
26 Comparison of radial displacement of piston, variants 1 (middle) www.compressortech2.com
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Variant 1 allows for a huge vibration, the cause of which may lie not only in the design of the bearing surface but also in the connection between the bearing surface and the piston rod. The stiffness is such that vibration occurs. In contrast, variant 2 exhibits a radial vibration of approximately +/- 25 microns, ignoring that the zero point is shifted. Further development will, therefore, build on this design. Excitation by forces on the piston, which arises, for example, from the opening of valves, should be considered, which is not yet the case in the simulation shown. The movement of the crosshead is associated with friction in the oil film; Figure 27 compares the two variants. The frictional work differs only slightly. Thus, the extreme reduction of the active surface in variant 1 has no significant positive effect on friction. Frictional work of almost one kilowatt heats the components; depending on the design, this also leads to considerable thermal distortion. The heat release is not uniform but is concentrated on one side, as shown in Figure 28. The figure shows the distribution of the normalized heat release averaged over one cycle. It can be seen that on one side of the crosshead, the heat release is approximately 30% of the other side, which leads to uneven heating.
4
Conclusion
Information about the lubricating film of hydrodynamic bearings is required to further develop components of a compressor's crank drive. Due to the measurement technology, experiments in which lubricant film thicknesses are measured are not easy, and the measurements are always limited to a few points. Therefore, it is desired to simulate assemblies such as the crosshead with pin bearing and the adjacent parts as
Acknowledgement The authors would like to thank Mr. Lang from IST Aachen for his shared knowledge and expertise.
74 | COMPRESSORTECH2 | AUGUST-SEPTEMBER 2026
FIGURE
27 Dissipation of Crosshead designs.
accurately as possible. Simulations always yield distributions of lubricant film thickness, pressures, temperatures, etc. It was demonstrated how a method, briefly described at the beginning, is applied to better understand components' functionality. For the pin bearing, possible solutions were demonstrated for critical operating conditions with little or no rod reversal, such as single-acting cylinders or diaphragm compressors. These solutions have been used in combustion engines for decades and have entirely replaced the designs commonly used in compressor construction. Nevertheless, quantitative analyses under compressor operating conditions are interesting. The minimum oil film thickness for double acting standard crossheads is below 10 m, it is therefore heavily influenced by local structural deformations and thermal expansions. Depending on the design the effects of thermal expansion of the bodies involved are significantly higher than pure structural deformations. To accurately simulate designs, which are not flexible enough to allow reasonable deformations it is crucial to account for the effects of thermal expansion (TEHD), as demonstrated by the simulations of the standard crosshead, where the film thickness distribution is reversed due to thermal distortion. CT2
28
FIGURE Crosshead variant 1, distribution of cycle averaged, normalized friction heat release.
REFERENCES: [1] Klaus Hoff, Egidius Steinbusch: Hydrodynamic calculation method for crosshead pin bearings especially under less rod load reversal loading. 6th Conference of EFRC 2008, Düsseldorf. [2] P.N. Duineveld, B. Brogle, C.H. Venner, S. van Loo: Advanced multilevel solution of journal paths in reciprocating compressors including bearing deformation. 8th Conference of EFRC 2012, Düsseldorf. [3]
FIRST Simulation Software (www.ist-aachen.de)
Roy R. Craig Jr., Mervyn C. C. Bampton: Coupling of substructures for dynamic analyses. AIAA Journal Vol.6 1968. [4]
[5] Kumar, A. und Booker, J.F.: A Finite Element Cavitation Algorithm. Trans. ASME, Ser. F, Journal of Tribology, Vol. 113, 1991, S. 261-276. [6] Milowitz, Kurt: Lager und Schmierung. List / Verbrennungskraftmaschine Band 8 Teil 1, 1962, Springer Verlag Wien. [7] Mayr, F.: Ortsfeste Dieselmotoren und Schiffs-dieselmotoren. List / Verbrennungskraftmaschine Band 12, 1960, Springer Verlag Wien.
Hill, A.: Modern Bearing Design and Practice. The Insitute of Marine Engineers, 1976, Bristol
[8]
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L e a r n h o w B l a c k s t o n e t r a n s f o r m s a s s e t d ata i n t o o p e r at i o n a l a d va n ta g e . B L A C K S T O N E I N D U S T R I A L . C O M
CORNERSTONES
OF COMPRESSION
The Worthington Pump and Machinery Company was a leader in industrial and marine compressors, pumps, reciprocating engines and other industrial machinery. It was a major supplier of large horizontal gas engine-compressors. By Norm Shade
Worthington Co.’s history included applications across many industries I n c.1920, with substantial experience in vertical engines as well as in compressors, Worthington developed “unibloc” integral gas engine-compressors. Shown in Fig. 1, these machines had vertical 11.5 in. (292 mm) bore, 12.0 in. (305 mm) stroke power cylinders and vertical 12.0 in. (305 mm) stroke compressor cylinders in an inline configuration, forward of the power cylinders on a common frame. Although they were a novel, space-saving idea, these types were limited to one or two compressor cylinders with modest diameters and pressure ratings. Reeves Gas Engine Company was thought to have been the first to introduce such machines in c.1915. But in 1927-1928, Worthington pioneered the industry’s first angle-type integral gas engine-compressor. Shown in Fig. 2, this design had vertical power
cylinders and horizontal compressor cylinders on a common frame. These fourcycle, spark-ignited 300 rpm angle integral engine-compressors were much more compact than the horizontals, but they averaged only 37.5 hp (28 kW) per cylinder. They were built with four, six or eight power cylinders and typically half that number of compressor cylinders. These machines gradually gained favor over horizontals for applications under about 300 hp (224 kW), but it would be more than another decade
before longer stroke, large-bore angle engine-compressors threatened the bigger horizontals used on long-haul natural gas pipelines.
Pipeline history
reasonable range to suit the particular conditions.”
In 1937, just three years before the company’s 100th anniversary, Worthington’s H. C. Lehm presented a paper to the American Gas Association in New York. Lehm’s paper highlighted the (then) current practice in the design and construction of gas compressing equipment used on the major pipelines and in various other fields. The last Cornerstones of Compression article focused on excerpts that highlighted Worthington’s assessment of large gas enginecompressor technology in 1937 – a time when horizontal gas engine-compressors had met the needs of the industry for over three decades and angle engine-compressors were still in their infancy. In this article, excerpts from the 1937 paper compare some of the “new” vertical and angle integral gas enginecompressors. The paper is quoted with minor edits. “These standard (horizontal) units used on the pipelines are equally adapted to compression in other fields such as manufactured gas distribution at comparatively low pressures, compression
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AUGUST-SEPTEMBER 2026 | COMPRESSORTECH2 | 77
1
FIGURE Worthington Unibloc gas engine-compressor with vertical engine and compressor cylinders on the same frame, c.1925.
“The design provides for considerable range in capacity as any particular size of power cylinder may be combined in units of from one to four compressor cylinders which may be of any diameter within a
>
CORNERSTONES
OF COMPRESSION
“The vertical power end in combination with the
of refinery gas and of the synthetic gases developed in chemical processes. In most cases, however, service of this sort calls for lower unit capacity than that of the pipeline compressor, a requirement which is met by several designs of fairly recent development. Prominent among these are the so-called angle types, in principle an adaptation from the old horizontal vertical blast furnace blowing engine but with the relative positions of the power and compression ends reversed. These units are built with the vertical power connecting rod and the horizontal compressor rod coupled to a common crank pin box or with separate power and compressor boxes side by side on a common crank pin. The design provides for considerable range in capacity as any particular size of power cylinder may be combined in units of from one to four compressor cylinders which may be of any diameter within a reasonable range to suit the particular conditions.”
entire station may be moved at minimum expense.”
‘Vertical power’
Types under review
“The vertical power end in combination with the compactly connected horizontal compressors results in all parts being in locations where they are most accessible, both for connection of the compressor suction and discharge piping and intercoolers where the latter are required, and for attendance and field adjustments. The floor space and foundation requirements are small, resulting in a fairly low station cost per horsepower. Where the cooling water supply is a problem, fans with a closed system may be used, reducing the water requirements to a minimum. An installation of this type is adapted to temporary locations as the
“Another type is the vertical multicylinder gas engine, with the compressor forming a separate unit, driven through a coupling from the end of the engine shaft, or with the compressor cylinders and running gear carried in an extension of the engine main frame. The latter forms a self-contained and compact unit and has nearly all the advantages of the angle type. It is not adapted to quite so wide a range in number and size of compressor cylinders but requires no more and in some cases less foundation and floor space. The inertia forces of this type of unit may be more completely balanced than those of the angle type,
c.1920
1927-28
With substantial experience in vertical engines as well as in compressors, Worthington developed “unibloc” integral gas engine-compressors.
78 | COMPRESSORTECH2 | AUGUST-SEPTEMBER 2026
compactly connected horizontal compressors results in all parts being in locations where they are most accessible, both for connection of the compressor suction and discharge piping and intercoolers where the latter are required.” 2
FIGURE Worthington angle gas enginecompressors in a natural gasoline plant, c.1935.
Worthington pioneered the industry’s first angle-type integral gas engine-compressor.
the degree depending upon the number and arrangement of the cylinders, power and compressor. For example, a unit consisting of four power cylinders and two compressor cylinders at one end has only slight unbalance remaining, and by placing a compressor cylinder at each end may be put in complete balance, corresponding to the six-cylinder power engine. In general, the free forces and unbalance couples of the vertical unit of five or more total cylinders are of minor magnitude compared to those of the horizontal compressor and, hence, the type has a decided advantage for installation on poor soil or in localities where transmission of vibration would be objectionable.”
Specific advantages “Where the power required approaches that of the standard horizontal doubleacting unit, the advantages of these types disappear to some extent, as they are inherently more expensive per horsepower in the large sizes and the saving in floor space and foundation is absorbed by the higher engine cost.” CT2 → Continued in the October issue
1937
(Three years before Worthington’s 100th anniversary) Worthington’s H. C. Lehm presented a paper to the American Gas Association.
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