The Lubricant That Doesn’t Lubricate

The fastest-growing fluid market for companies like ExxonMobil, Shell, FUCHS, Castrol, and Lubrizol has nothing to do with turbines, hydraulic presses, or gearboxes. It’s a stainless steel tank full of servers submerged in dielectric fluid.

The data center immersion cooling fluids market is projected to grow from roughly $190 million in 2025 to over $840 million by 2032, expanding at nearly 24% annually. By the broader measure of the total immersion cooling market, including hardware and integration, some analysts put the 2025 figure above $4 billion.

These fluids never form a hydrodynamic film. They never protect metal-to-metal contact. They carry no EP or AW additive packages. And yet the companies formulating and selling them are the same organizations that fill your lubricant reservoirs. The base stock chemistries, the supply chains, and increasingly the technical service models are converging.

Why “Lubrication” Is Moving into Thermal Management

Up to 40% of the energy consumed by a typical data center goes toward preventing it from overheating. That was manageable when servers ran at moderate power densities and air cooling could handle the load. It is no longer manageable. AI training clusters routinely push rack power densities above 50 kW, and next-generation GPU (Graphics Processing Unit) configurations are targeting 100 kW per rack and beyond. Air resists heat transfer, which is the reason that double-pane windows insulate a room so well. Water conducts heat roughly 25 times better than air at rest. In motion, the gap widens further.

A May 2025 lifecycle assessment published in Nature by researchers at Microsoft and WSP Global quantified the efficiency gains across three liquid cooling technologies compared to traditional air cooling. Cold plate systems delivered a 15% reduction in energy consumption and a 31% decrease in water use. Single-phase immersion improved those numbers to 15% and 45%, respectively. Two-phase immersion outperformed both, yielding a 20% energy reduction and 48% less water consumption.

Goldman Sachs estimates that data centers already consume 1–2% of global electricity, a figure that could nearly double by the end of the decade. In Ireland, data centers account for roughly 17% of national electricity consumption and could reach a third by 2026. The U.S. Department of Energy estimates domestic data centers used more than 4.5% of total U.S. electricity in 2025, with cooling systems responsible for 25–40% of that draw.

For the lubrication community, the conceptual shift is this: in rotating machinery, the fluid manages friction and wear, with heat removal as a secondary function. In data center immersion, heat removal is the entire job. The fluid’s role flips from tribological to thermal. But the underlying science of fluid chemistry, oxidation stability, contamination control, and condition monitoring is remarkably similar.

Up to 40% of the energy consumed by a typical data center goes toward preventing it from overheating. Water conducts heat roughly 25 times better than air at rest. In motion, the gap widens further.

Immersion Fluids vs. Traditional Lubricants: What’s the Same, What’s Not

Immersion cooling comes in two fundamental variants:

Single-phase immersion uses synthetic hydrocarbons (polyalphaolefins, gas-to-liquid bases), synthetic esters, or bio-based oils that remain in liquid state throughout the cooling cycle. The fluid circulates through a tank containing fully submerged servers, absorbs heat by convection, and transfers it to a heat exchanger. Synthetic hydrocarbons held roughly 41% of the 2024 market revenue, favored for their low viscosity and strong material compatibility. These are chemically familiar to anyone who has worked with Group IV or Group V base stocks.

Two-phase immersion uses fluorinated chemistries, including hydrofluoroethers (HFEs), perfluorocarbons (PFCs), and hydrofluoroolefins (HFOs), that boil at low temperatures, typically 50–60°C. The phase change from liquid to vapor absorbs significantly more heat per unit volume than single-phase convection. It’s thermally superior, but as we’ll discuss, it carries serious regulatory and supply chain risk.

What should feel immediately familiar to lubrication professionals is the list of fluid performance parameters. The Open Compute Project (OCP), the industry’s primary standards body for data center hardware, has published a Base Specification for Immersion Fluids that reads like a lube  oil spec sheet translated into a different application. Viscosity targets, thermal conductivity requirements, flash point minimums, pour point behavior, oxidative stability expectations. The OCP specification sets a single-phase viscosity target of 1.5 × 10⁻² N·s/m² at 40°C (approximately 17cSt at at 40°C), noting that lower viscosity fluids allow higher fin density in heatsink design and better thermal performance overall.

What’s different is the failure mode. In rotating machinery, inadequate lubrication leads to metal-to-metal contact, adhesive wear, and ultimately seizure. In immersion cooling, the catastrophic failure is thermal runaway, where the fluid can no longer remove heat fast enough and server components exceed their thermal limits. Dielectric strength replaces film thickness as the critical performance metric. There are no wear particles to count, but there are degradation byproducts to monitor, contamination limits to enforce, and material compatibility issues that will sound very familiar.

Side-by-Side: Industrial Lubricant vs. Immersion Cooling Fluid

The Risk Landscape: Material Compatibility, Oxidation, and Contamination

The risks that data center operators are discovering are risks that lubrication professionals have been managing for decades.

Material compatibility is the most immediate concern. OCP’s material compatibility guidelines, published as an open-source reference document, warn that dielectric fluids can stiffen cable sheathing, remove identification markings, soften or dissolve adhesives and plastics, and interact unpredictably with certain coatings. The guidelines explicitly state that mineral oils should be avoided for immersion use due to impurities including sulfur, nitrogen, and aromatic compounds that create compatibility problems. Synthetic hydrocarbons and esters are the preferred chemistries.

Anyone who has managed a hydraulic system conversion or dealt with seal compatibility issues will be familiar with compatibility concerns. In a data center however, this concern is on a bigger scale. A single immersion tank can contain hundreds of servers, each with dozens of distinct materials in contact with the fluid. Cables, connectors, thermal interface materials, PCB substrates, conformal coatings, and adhesives all sit in the same bath. A compatibility failure is also on a larger scale than lubricants. Incompatibility doesn’t ruin a pump seal but destroys millions of dollars of compute hardware. Incompatibility examples can be seen in Figures 2 and 3.

A single immersion tank can contain hundreds of servers, each with dozens of distinct materials in contact with the fluid. A compatibility failure here doesn’t ruin a pump seal. It destroys millions of dollars of compute hardware.

Oxidation and degradation follow familiar pathways but with a different stress profile. Even though immersion systems are often designed as closed-loop, oxygen ingress is never zero. At sustained operating temperatures (typically 40–60°C bulk, with localized hot spots near chips exceeding 80–100°C), the fluid undergoes the same radical chain oxidation you see in lubricating oils. The rate accelerates with copper exposure from bus bars, connectors, and heat sinks, which act as potent catalysts.

But the oxidative stress is relentless: 24 hours a day, 365 days a year, with no shutdown cycles, no seasonal variation, and no opportunity for the fluid to rest. Oxidative degradation proceeds, acid numbers escalate, and fluid properties deteriorate. Therefore, monitoring these parameters matter in a server tank just as much as it does in a critical compressor train.

Contamination sensitivity in data center cooling systems is similar to many industrial lubricant cleanliness requirements. OCP’s August 2025 Technology Cooling System (TCS) guidance specifies that microchannel heat exchangers require filtration to below 25 μm. The document emphasizes that fluid quality standards, detailed flushing procedures, and biofilm prevention protocols are essential for reliable operation.

Pipe materials prone to corrosion, particularly carbon steel, are prohibited. Pre-commissioning guidelines call for deionized water flushes meeting ASTM D1193 conductivity requirements, hydrostatic pressure testing, and documented cleanliness verification before the first drop of coolant enters the system. Anyone who has managed an EHC or hydraulic system to low NAS 1638 or ISO 4406 cleanliness codes will recognize the criticality of contamination control.

“Forever Chemicals” Split the Market in Two

No discussion of immersion cooling fluids is complete without addressing PFAS (per- and polyfluoroalkyl), also referred to as Forever Chemicals. This family of chemicals has incredibly strong carbon-fluorine bonds that do not break down in the human body or in the environment, leading to toxic bioaccumulation.

In December 2022, 3M announced it would stop manufacturing all PFAS chemicals by the end of 2025. That single decision effectively destroyed the supply chain for two-phase immersion cooling in data centers. The three fluids that made the technology possible, Novec 7100, Novec 649, Fluorinert FC-72, are gone. The last day to place a new Novec order was March 31, 2025. 3M was staring down over 4,000 lawsuits and a $12.5 billion settlement with more than 11,000 U.S. public water systems alleging PFAS contamination in drinking water.

The three fluids that made two-phase immersion cooling possible, Novec 7100, Novec 649, Fluorinert FC-72, are gone. One corporate decision wiped out the entire supply chain.

The regulatory pressure extends well beyond 3M’s exit. The European Chemicals Agency (ECHA) is evaluating a PFAS restriction proposal submitted by five EU member states under REACH that covers over 10,000 substances. Updated proposals published in August 2025 expanded exemptions from 26 to 74, including longer transition periods for certain heat transfer applications. ECHA’s final opinions are expected by end of 2026, with European Commission restriction legislation anticipated in early 2027. In the United States, the EPA has classified certain PFAS compounds as hazardous substances, imposing stringent waste management and reporting requirements. Several U.S. states are pursuing their own restrictions.

The practical result is a bifurcation in the immersion cooling market. Single-phase systems using hydrocarbon-based fluids (PAOs, synthetic esters, bio-based oils) are positioned as the safe, scalable path. They avoid PFAS entirely and use chemistries that lubricant companies already manufacture at industrial scale.

Two-phase systems are in limbo, waiting for Chemours and others to commercialize PFAS-free alternatives like HFO-based fluids with zero ozone depletion potential. Commercial production of Chemours’ Opteon 2P50 is targeted for 2026, and Samsung has already qualified the fluid. But as one industry analysis noted, any vendor building a two-phase product around a fluorinated fluid is building on ground that may shift under them within 18 months.

For the lubrication community, the PFAS collapse is more than a data center story. PFAS are used in specialty lubricants and greases due to their superior heat resistance, antiwear and anticorrosion properties. These regulatory changes require reformulation of hundreds of greases and lubricants. It’s a good reminder that supply chain resilience isn’t just about having a backup supplier. It’s about understanding the regulatory trajectory of your base chemistries.

Who Owns the Fluid Spec? OEM vs. Operator Dynamics

In industrial rotating machinery, the power dynamic around fluid specifications is well established. The OEM, whether it’s Volvo, Siemens Energy or Caterpillar, publishes an approved lubricant list. The end user follows it, often because the equipment warranty depends on compliance. Lubricant suppliers invest heavily in OEM approvals. The OEM holds the leverage.

Data centers have inverted this model.

OCP’s specifications are publicly available, their meetings are open and recorded, and their technical documents are published under Creative Commons licensing. The lubrication industry doesn’t have anything like it.

The Open Compute Project (OCP) sits at the center of the emerging standards landscape. OCP’s Immersion Sub-Project operates through dedicated technical committees for Fluids, Solutions, Reliability, and IT Equipment integration. These committees are developing open-source specifications, reference designs, and best practices through a volunteer-driven process that unites technology providers, end users, researchers, and fluid manufacturers. Their Immersion Requirements sub-project exists specifically to separate marketing claims from engineering reality, ensuring what OCP calls “accurate and factual technology positioning.”

This is an open-standards approach to fluid qualification that doesn’t have a clear parallel in traditional lubrication. ASTM and ISO develop test methods, but they don’t publish application-specific fluid requirements the way OCP does. OEM lubricant approvals are proprietary and often opaque. OCP’s specifications are publicly available, their meetings are open and recorded, and their technical documents are published under Creative Commons licensing.

Meanwhile, the hyperscalers are writing their own rules. Microsoft, Google, and Meta have internal testing programs and qualification protocols that effectively function as proprietary fluid specifications. When Microsoft validates a two-phase immersion tank at its Quincy, Washington campus, or when Google standardizes immersion-cooled TPU pods across its fleet, those decisions influence the market. The hyperscalers have more testing infrastructure, more purchasing leverage, and more operational data than any traditional OEM.

Chip manufacturers add another layer. In May 2025, Shell became the first immersion fluid provider to receive certification from Intel for its 4th and 5th generation Xeon processors, including a warranty rider for immersion-cooled chips. Intel estimated the electricity consumption reduction at up to 48%. This mirrors how turbine OEMs approve specific lubricant brands, but the twist is that Intel isn’t the system integrator; it’s the component manufacturer inside someone else’s machine.

Colocation providers and enterprise data center operators don’t have Google’s testing labs or Microsoft’s engineering teams. They need standardized, vendor-neutral fluid specifications they can trust. That is exactly the role OCP is filling, and it represents a model the lubrication industry could learn from. OCP’s transparent, committee-driven approach to fluid qualification stands in contrast to the often opaque process by which industrial OEMs approve or delist lubricants.

Why Lubricant Companies Are Repositioning Around Data Centers

The number of companies competing in the immersion cooling fluids market tells the story. Shell, ExxonMobil, Castrol, FUCHS, Lubrizol, Valvoline, TotalEnergies, PETRONAS, Cargill, and ENEOS are some of the major lubricant companies focused on data center immersion coolants.

Industrial lubricant volumes in traditional applications are mature in most developed markets. Electrification is shrinking some automotive and drivetrain lubricant categories. Data center fluids offer a new, high-growth volume play using chemistries these companies already manufacture. PAOs, synthetic esters, Group III+ bases, and bio-based oils are all viable single-phase immersion fluids.

Lubricant companies bring global supply chain scale, established quality management programs and technical service teams with decades of experience in condition monitoring and fluid analysis. In addition, they have deep institutional knowledge of oxidation chemistry, additive interactions, and degradation mechanisms. A lubricant company that already produces thousands of tons of PAO annually doesn’t face the same scale-up challenges as a venture-backed fluid startup trying to commercialize a novel chemistry.

Industrial lubricant volumes in traditional applications are mature. Electrification is shrinking some categories. Data center fluids offer a new, high-growth volume play using chemistries these companies already manufacture.

Oil manufacturers are also focused on the sustainability aspect. TotalEnergies’ BioLife product line demonstrates that plant-based fluid stocks can match petrochemical performance while biodegrading rapidly enough to satisfy EU waste directives. Cargill brings agricultural feedstock expertise. Bio-based lubricants have been a perennial topic at lubrication conferences for years. Data centers are giving the category a new, high-volume market to accelerate product development.

FUCHS has been particularly aggressive, signing a long-term partnership with Anhui Zhongding Intelligent Thermal Management Systems in China for data center immersion solutions in January 2024. Shell’s Intel certification positions it as the trusted fluid in one of the largest chip ecosystems on earth. Lubricant companies are quickly capitalizing on these emerging data center opportunities. 

What This Means for Lubrication Professionals

The skills that define precision lubrication, fluid analysis, contamination control, material compatibility assessment, condition-based maintenance, and the ability to understand degradation mechanisms at a molecular level, are exactly what data center operators need as they transition from air to liquid cooling. The application is different. But the science is the same.

Consider what the OCP’s own documentation demands. Regular fluid testing with defined alarm limits. Material compatibility protocols. Cleanliness targets for particulate and ionic contamination. Flushing and commissioning procedures. Biofilm monitoring. Thermal performance trending over the fluid’s service life. These are the same program elements that world class lubrication programs require.

The data center immersion cooling market is growing at nearly 24% annually. The broader liquid cooling market nearly doubled in 2025, approaching $3 billion, and is forecast to reach $7 billion by 2029. Only 45% of data centers now run purely on air cooling, down from 48% just a year earlier, with 59% planning to implement liquid cooling within five years. This is a rapidly evolving market where fluids expertise will be demanded.

The definition of “lubricant” is expanding. It now includes fluids that never touch a bearing but carry the same chemical DNA, require the same analytical rigor, and depend on the same foundational science. The professionals who recognize this early won’t just watch the transition. They’ll lead it. 

The Data Center Power Boom and What It Means for Traditional Lubrication Markets

The conversation about data centers and fluids tends to focus on what’s inside the server tank. Immersion cooling is new, it’s technically interesting, and it represents a genuine expansion of what the word “lubricant” means. But there is a second story running in parallel that may impact the lubrication industry’s bottom line. Power generation.

The scale of the power buildout is difficult to overstate. The International Energy Agency projects that global data center electricity consumption will roughly double to around 945 TWh by 2030, growing at about 15% per year. That growth rate is more than four times faster than electricity consumption growth from all other sectors combined. Gartner’s estimate is even higher, projecting worldwide data center electricity consumption will rise from 448 TWh in 2025 to 980 TWh by 2030. In the United States specifically, data centers consumed approximately 176 TWh in 2023, roughly 4.4% of total national electricity. The Department of Energy and Lawrence Berkeley National Laboratory project that figure could reach 6.7% to 12% of all U.S. electricity consumption by 2028.

Gas turbines are the biggest technology in this buildout. Natural gas supplied more than 40% of U.S. utility-scale electricity in 2023, and developers currently plan 18.7 GW of newly constructed combined-cycle gas turbine capacity through 2028. Globally, gas-fired power capacity in development rose 31% in 2025 alone, reaching a total of 1,047 GW across all stages of planning and construction. The Global Energy Monitor reports that 2026 could set a record for new gas power projects coming online, potentially exceeding the previous high of 100 GW added in 2002 during the wave of gas-fired construction that followed electricity market deregulation.

Data centers are a primary driver of this surge. Meta’s Hyperion project in Louisiana will use three H-class natural gas turbines as part of a facility that will eventually scale to 5 GW. Elon Musk’s xAI has ordered up to 60 gas turbines for its Memphis supercomputer facility. Boom Supersonic signed a $1.25 billion deal to supply Crusoe, an OpenAI data center developer, with 29 jet-engine-derived gas turbines. The Oracle/OpenAI Stargate project in Abilene, Texas is deploying GE Vernova and Solar Turbines units to deliver more than 1 GW of on-site power. Industrial Info Resources expects natural gas power plant investment to top $35 billion annually and sustain that level for several years, reaching a pace of construction not seen in two decades.

Gas turbine lead times have stretched to five to seven years in some cases, and turbine prices have risen 195% since 2019 according to Wood Mackenzie, reflecting the intensity of demand. OEMs like GE Vernova, Siemens, and Mitsubishi Heavy Industries report order backlogs at record highs.

Diesel generators represent a hidden fleet of enormous scale. Data centers require backup power systems capable of sustaining the full facility load during grid outages, and diesel generators remain the dominant technology. Just in the state of Virginia alone, over 10,500 diesel generator units had been permitted for data centers by the end of 2025, with a total capacity of 27 GW. That is equivalent to the power usage of roughly 20 million U.S. households, in a state with fewer than 4 million homes. Nationwide, the U.S. data center backup diesel fleet is expected to approach 67 GW of installed capacity by the end of the decade, roughly 35 nuclear power plants worth of generating capacity.

Virginia alone has permitted over 10,500 diesel generator units for data centers, with 27 GW of total capacity. That’s enough to power roughly 20 million U.S. households, in a state with fewer than 4 million homes.

A new class of power plant operator. More than 25% of new data center facilities above 500 MW will have behind-the-meter power generation by 2030, up from just 1% today. This means data center operators will be managing their own gas turbines, reciprocating engines, and combined-cycle plants, not the grid utility. Many of these data center operators have deep expertise in IT infrastructure and thermal management but no institutional experience managing rotating equipment maintenance programs. They will need lubrication engineers, fluid analysis programs, vibration monitoring, and contamination control technologies.

Renewables complete the picture. The data center buildout is simultaneously driving renewable energy procurement at unprecedented scale. Microsoft, Google, Amazon, and Meta are among the world’s largest corporate buyers of wind and solar capacity. In Europe, the major hyperscalers each account for roughly 4 to 9 GW of total corporate energy procurement.

The data center industry doesn’t just redefine what a lubricant is. It amplifies demand for every lubricant category that already exists: gas turbine oils, diesel engine oils, hydraulic fluids, wind turbine gear oils, and grease. Where turbines go, lubrication programs follow.

References

1. Open Compute Project, “Immersion Sub-Project Overview,” OCP Cooling Environments, 2025. Available: https://www.opencompute.org/projects/immersion
2. Open Compute Project, “Base Specification for Immersion Fluids,” Revision 1.0, Version 1.0, December 2022. Available: https://www.opencompute.org/documents/ocp-base-specification-for-immersion-fluids-20221201-pdf
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Hydraulic presses in Oriented Strand Board (OSB) mills are central and indispensable to OSB production. They exert an immense, uniform force required to compress wood strands and resin into durable panels, operating under exacting temperature and pressure conditions. The performance of hydraulic presses depends critically on the quality and condition of the hydraulic oil.

The Vital Role of Hydraulic Oil

Hydraulic oil in OSB presses serves multiple roles:

• Power Transmission: Hydraulic oil transmits power from pumps to press cylinders, enabling precise compression.
• Lubrication: Reduces friction in pumps, valve spools, and cylinders.
• Heat Transfer: Acts as a coolant, absorbing and dissipating heat from critical components.
• Sealing and Contamination Control: Prevents contamination ingress, maintaining system integrity.

Hydraulic Oil Failure: Oxidation and Varnish

Despite its crucial role, hydraulic oil is susceptible to failure, especially due to oxidation and subsequent varnish formation. Oxidation, a reaction with oxygen accelerated by heat, pressure, moisture, and catalytic metals, depletes antioxidants and generates harmful byproducts.

When oxidation takes hold, varnish becomes the silent killer of hydraulic precision.

Varnish, an insoluble, sticky deposit formed from these oxidation byproducts, accumulates on critical components, especially servo and proportional valves. This buildup is analogous to cholesterol plaque in arteries, restricting fluid flow, reducing responsiveness, and increasing operational risks.

Operational Impact of Oil Degradation

When hydraulic oil fails:

• Press Performance Suffers: Reduced valve responsiveness leads to inconsistent press forces, resulting in poor board quality and defective products.
• Maintenance Costs Escalate: Varnish buildup necessitates frequent component replacements, system flushes, and increased downtime.
• Energy Efficiency Drops: Oxidized, varnish-contaminated oil increases viscosity and blocks oil flow channels, raising power demands and operating costs.
• Safety and Environmental Risks Increase: Potential leaks and compromised components present significant hazards. Oxidized oil is known to deteriorate seals, leading to more leaking and increased risk.

Targeting Varnish at Its Source for Lasting Results

To combat these challenges, Fluitec and ExxonMobil developed Mobil Solvancer, an innovative oil-soluble cleaner. Mobil Solvancer dissolves varnish deposits effectively, analogous to a solvent clearing blocked pipes, immediately restoring system responsiveness. It also provides long-term protection, minimizing varnish recurrence, improving servo valve response times, and extending equipment life.

Inside the GP Clarendon Hydraulic Recovery Journey

GP Clarendon OSB Mill experienced significant varnish buildup in hydraulic systems after a prolonged shutdown, despite using Mobil DTE 25 and DTE 25 Ultra oils. Frequent servo valve failures were costing around $40,000 per quarter.

Identifying the Root Cause of Hydraulic Varnish

Analysis revealed high varnish levels indicated by elevated Membrane Patch Colorimetry (MPC) values (66dE). The mill implemented a 5% treatment rate of Mobil Solvancer (approximately 40 drums) combined with enhanced kidney-loop filtration.

Results Achieved

Within 2.5 months, remarkable improvements were observed:

• MPC values dropped from 66dE to 26dE.
• Ultra Centrifuge (UC) ratings improved from 4 to 1.
• Servo valve failures decreased from six per quarter to zero, showcasing substantial reliability improvements.

Ensuring Long-Term Reliability and Oil Health

With proven success, GP Clarendon scheduled a complete system oil change and plans to install permanent high-efficiency filtration in March 2025, ensuring long-term system integrity and performance.

Key Findings and Operational Takeaways

Effective management of hydraulic oil condition is crucial for maintaining optimal productivity and reliability in OSB mills. Mobil Solvancer demonstrates exceptional performance, significantly reducing varnish deposits, enhancing system efficiency, reducing maintenance costs, and ensuring consistent product quality.

As demonstrated by GP Clarendon’s experience, proactive maintenance coupled with Mobil’s industry-leading hydraulic oils can transform operational reliability in industrial hydraulic systems.

In the high-stakes arena of power generation, turbine oil life has always dictated the tempo of reliability. A century of operating experience taught plant engineers one brutal truth: once an oil’s antioxidant package collapses, varnish doesn’t politely knock—it kicks the door in. The remedy was equally blunt. Drain. Flush. Refill. Get the unit back online and hope the schedule and budget survive the ordeal.

That reactive ritual hid monumental costs. A forced turbine outage can swallow $250,000 to $1,000,000 per day in lost generation revenue, while a single high‑temperature flush consumes significant new oil, dozens of labor‑hours, and tens of thousands of dollars. Worse, none of it addresses the root cause; the fresh charge begins oxidizing the moment the turbine starts spinning.

A New Paradigm for Turbine Oil Management

In‑situ antioxidant replenishment rewrites that playbook. By selectively re‑injecting antioxidants—precisely matched to the base stock’s solvency—the oil’s oxidative resistance is restored without interrupting production. Think of it as administering a targeted vitamin boost rather than performing an organ transplant.

Key performance indicators such as RULER® antioxidants (D6971) and Rotating Pressure Vessel Oxidation Test (D2272) values rebound while varnish potential plummets—often within a single maintenance shift.

Replenishment turns turbine oil from a consumable into a long-life performance asset—without interrupting production.

The implications extend far beyond chemistry. Extending oil life from a typical 7–10 years to 20 years or more eliminates at least two full drain‑and‑flush cycles over a turbine’s design life, slashing cradle‑to‑grave carbon intensity by 100 t CO₂e per machine. Just as importantly, replenishment keeps the unit’s reliability curve flat, removing the “bathtub” spike in failure probability that coincides with oil change‑outs. In short, it turns lubrication from a consumable into an asset, aligning maintenance strategy with the realities of decarbonization and relentless uptime expectations.

Ensuring Reliable Outcomes With Antioxidant Replenishment

Traditionally, when turbine oils experienced antioxidant depletion, the default response was to completely replace the oil, typically involving a full system flush. Yet this costly and disruptive routine isn’t always necessary. In fact, even when the antioxidant stability drops to around 25%, the underlying base oil often remains in good condition. Addressing the issue early by replenishing these critical antioxidants can prevent lasting damage. Achieving this, however, demands specialized expertise in formulation chemistry and thorough preliminary testing to ensure the right approach.

Even at 25% antioxidant remaining, base oils are often still viable—replenishment prevents costly, unnecessary oil changes.

Before applying antioxidant replenishment in actual turbine operations, it is essential to evaluate the long-term effectiveness of the antioxidant concentrate through laboratory testing. The Turbine Oil Performance Prediction (TOPP) test serves as an ideal evaluation method, offering precise insights into antioxidant performance and deposit tendencies under controlled conditions.

Consider an example from laboratory trial as shown in Fig. 1: a fresh turbine oil subjected to stress conditions for 12 weeks saw its Rotating Pressure Vessel Oxidation Test (RPVOT) value plummet from 1091 minutes to just 304 minutes, accompanied by a significant increase in Membrane Patch Colorimetry (MPC) from 1 to 59, clearly indicating oxidation damage and visible deposits.

Splitting this stressed sample and treating half with DECON AO resulted in performance improvements. After an additional six weeks under identical conditions, the untreated portion deteriorated further.

In contrast, the treated sample recovered, ultimately reaching an RPVOT of 949 minutes, exhibiting minimal varnish potential, and showing no glassware deposits. This clear demonstration underscores the practical effectiveness of antioxidant replenishment in maintaining oil integrity and extending its operational life.

The laboratory experiment illustrates the effectiveness of Decon AO. Yet, transitioning this success from the controlled environment of the lab to the dynamic realities of field operations requires preparation and validation. To safely apply antioxidant replenishment in real-world conditions, the following process is suggested to mitigate risk:

1. Begin with a baseline analysis, adhering to ASTM D4378 protocols. Oils that show severe degradation—particularly those with acid numbers greater than 0.4 mg KOH/g or significant water contamination—are usually disqualified.
2. Carefully blend the in-service oil with the selected antioxidant additive concentrate, typically around a 3% concentration. This mixture should then be heated to 65 °C and maintained at this temperature for a 24 hours.
3. Conduct baseline testing once more on the treated oil blend.
4. Evaluate the results by:
   • Confirming that no negative changes occur regarding performance indicators, such as Membrane Patch Colorimetry (MPC), rust inhibition, demulsibility, air release, and foam characteristics.
   • Verifying significant improvements in the oil’s oxidative stability, measured through RPVOT and RULER results.
5. If testing demonstrates no adverse effects and shows substantial enhancement of oxidative stability, the in-service oil is deemed suitable for antioxidant replenishment. If these criteria aren’t met, antioxidant replenishment should not proceed.

This process is summarized in Figure 2.

A Quiet Revolution Accelerates

The momentum behind antioxidant replenishment is building quickly. Back in 1954, as Elvis Presley recorded his groundbreaking hit, “Rock Around the Clock,” which symbolized the revolutionary birth of rock ‘n’ roll, another revolution was quietly underway in the oil industry.

Norris and White, innovators at Socony Vacuum (now ExxonMobil), introduced a groundbreaking concept—small, precise additions of additives that could stabilize turbine oils without the costly disruption of full oil replacements. For decades, this innovative yet understated approach quietly supported power plants, often without much fanfare, as oil manufacturers discreetly offered antioxidant top-ups to help resolve customer challenges.

Today, however, what began as a subtle shift is rapidly gaining industry-wide recognition. Recent years have seen a surge of formal endorsements, technological advancements, and strategic implementations by industry leaders, highlighting a decisive shift towards antioxidant replenishment as an accepted best practice. This evolution underscores the industry’s increasing alignment with sustainability, cost efficiency, and proactive maintenance principles.

Much like Rock ‘n’ Roll transformed popular culture, antioxidant replenishment is steadily transforming turbine oil management, redefining the way power plants approach reliability, sustainability, and operational efficiency.

From Theory to Reality: The Proven Path of Antioxidant Replenishment

The conventional approach to managing turbine oil degradation—drain, flush, and refill—has historically been both costly and environmentally taxing. However, in-situ antioxidant replenishment technology is rapidly reshaping this narrative.

What was once theory is now proven: antioxidant replenishment extends oil life while cutting cost, downtime, and emissions.

By selectively restoring antioxidants matched precisely to the oil’s chemistry, operators effectively halt oxidation without disrupting turbine operation. This innovative approach not only restores oxidative resistance and drastically reduces varnish potential but also extends oil life, lowering lifecycle costs and significantly decreasing carbon emissions.

Industry adoption of antioxidant replenishment is accelerating, evidenced by multiple endorsements, technical standards, and real-world applications demonstrating tangible benefits. What was once a theoretical possibility is now a proven industrial practice, heralding a future where proactive lubricant management enhances reliability, environmental stewardship, and operational efficiency.

References

1. H. D. Norris and R. V. White, “Antirust Agent,” U.S. Patent 2 490 744, 13 Dec 1949.
2. H. D. Norris and R. V. White, “Turbine-Oil Antioxidants,” U.S. Patent 2 697 074, 14 Dec 1954.
3. Mitsubishi Heavy Industries, “Antioxidant Refill System and Method,” JP 2023-160717 A, 22 Jun 2023.
4. C. Bequette et al., “Integrated System and Method for Automatic Rejuvenation of Turbine Oil,” U.S. Patent 11 639 771 B2, 2 May 2023.
5. ASTM International, ASTM D7155-20 – Standard Practice for Evaluating Compatibility of Mixtures of Turbine Oils, West Conshohocken, PA, 2020.
6. G. Livingstone and J. Joy, “Antioxidant Replenishment Doubles Turbine-Oil Life: Mesquite Power Case Study,” OilDoc Conference Proceedings, Rosenheim, 2017.  
7. MHI Power Systems, “On-Site Oil Regeneration Through Adsorption and Antioxidant Replenishment,” MHI Technical Review, vol. 61, no. 2, pp. 30–35, 2024
8. Vanderbilt Chemicals LLC, VANLUBE ® 407 as a Top-Treat Antioxidant for Turbine Oils (technical brochure), 2017.
9. A. B. Lantos, “Assessing Oxidation Condition and Lubricant Refreshment in Turbine Oils,” Machinery Lubrication, Jul 2020.
10. G. Livingstone, “The Journey to Fill-for-Life,” Machinery Lubrication (White Paper), 2020.
11. E. Perez, “Extending Lubricant Life Through Antioxidants,” Turbomachinery International, vol. 55, no. 3, pp. 28–32, 2014.
12. Thermal-Lube Inc., Additive Reconstruction of Oils (technical bulletin), 2021.

What is Lubricant Foaming?

Lubricant foaming is a deceptively complex phenomenon often dismissed as mere surface bubbles on top of oil reservoirs. Yet seasoned lubrication engineers and tribologists understand the critical threat foaming poses to lubricant performance and equipment reliability.

In this article, we delve into the mechanisms behind foam formation, its adverse impacts, standardized testing methods, antifoam additive technologies, and actionable solutions to address this prevalent industry challenge.

Understanding Foam vs. Air Release

To effectively manage lubricant foaming, it’s crucial to differentiate between foam properties and air release characteristics. Air release refers to the lubricant’s ability to rapidly separate entrained air bubbles and release them, thereby preserving oil integrity. Foam formation, however, involves the stabilization of air bubbles at the oil surface. Imagine a pint of beer—bubbles within the beer represent air release behavior, while the foam atop symbolizes lubricant foaming (See Figure 1).

This is what it looks like if you are a drop of oil flowing through a return line from a turbine bearing, back to the reservoir. The bright, flashing lights are air bubbles all around you. If the turbine oil has poor foaming performance, it’s easy to see how easy it is for foam to develop!

Each phenomenon impacts equipment differently. Entrained air compromises lubrication effectiveness, accelerates oxidation, enhances compressibility, induces microdieseling, and contributes to cavitation. Particularly problematic in hydraulic systems, this can lead to spongy responses and reduced valve precision. Conversely, foam on top of lubricant reservoirs disrupts lubricant film consistency, hampers heat dissipation, and presents safety risks if an overflow occurs.

Causes of Foam Formation

Lubricant foam arises primarily from the entrapment and stabilization of air bubbles within the fluid. There are several potential causes, but foam is generally initiated by either a mechanical or chemical reason.

Mechanical Reasons for Foam

Mechanical agitation, such as rapid flow rates, pump operation, gear mesh interactions, seal leaks, and bearings agitation, may introduce air bubbles into the oil. It can be particularly challenging for these bubbles to dissipate in high-viscosity fluids (especially at low temperatures), as these fluids impede efficient air release.

Poor reservoir design can also contribute to lubricant foaming due to deficient baffling and insufficient residence time for air to settle out of the oil. Additionally, if the return line is positioned above the surface of the lubricant, significant splashing may occur, resulting in foam. Finally, systems that are under vacuum with a degasification or demister system will also be more prone to foam generation.

Chemical Reasons for Foam

Contaminants are a common cause of foam formation. Moisture and degraded additives may reduce the oil’s surface tension, allowing the bubbles to form more easily and making the foam more stable. Particulate, soot, or dispersants may also act as foam-stabilizing nucleation sites.

Oxidation byproducts are also polar, which reduces surface tension and increases foaming tendencies. Some types of contaminants may form films at the air-oil interface, thereby increasing the interfacial tension of the fluid and making it more difficult for bubbles to collapse.

Foam After an Outage?

It is common to see foam occurring after an outage, as human interaction with the lubricant system always introduces risk. Sometimes, maintenance crews walking over your equipment during downtime may inadvertently crack a pipe connection leading to a pump, which can introduce new sources of air. Or, contaminants may inadvertently enter the system during outages, causing chemical changes in the oil and creating more opportunities for foam.

The first step in diagnosing a foam issue is to determine if it is a mechanical issue or a chemical issue. Fortunately, this can be easily accomplished by performing oil analysis tests.

Standardized Foam Testing Methods

Determining the foaming tendencies and stability in used oil analysis is standard in most commercial laboratories by following one of the three tests:

ASTM D892 (or DIN 51566)

This test was developed in the mid-20^th century.  It measures foaming tendencies and foam stability, performed in three sequences: 24 °C, 93.5 °C, and then again at 24 °C. In each sequence, air is blown through the oil for 5 minutes, and foam is measured immediately after (foam tendency) and again after 10 minutes (foam stability).

The results are measured in mL and separated by tendency/stability for each sequence. For example, 450/0 means that 450 mL of foam was initially generated (tendency) and 0 mL of foam remained after 10 minutes (stability).

ASTM D6082: High-Temperature Foaming Characteristics

This testing method was developed to measure foam in hotter operating environments, as the test is performed at 150°C. The test is interpreted in a similar way to D892. The first value represents the foam tendency, measured in mL after 5 minutes of air blowing, and the second value represents the foam stability, also measured in mL after 10 minutes of rest.

Flender Foam Test, ISO 12152:2002

The Flender Foam Test measures foaming behavior (formation and stability) of lubricants under mechanical stress at elevated temperatures, simulating the conditions found in Flender gearboxes. The fluid is stressed in a specialized gear test rig (conveniently named Zahnradversuchgerät!) at 90°C for 5 hours with a gear speed of 1,450 rpm.

It’s typically used on ISO VG 150 – 320 industrial gear oils. The results are typically reported as Foam Formation Height (mm), Foam Collapse Time (secs), Air Entrainment (visual/subjective), and Overflow or Oil Loss (pass/fail).

Effective Antifoam Additives

New oils are typically formulated with antifoam additives to minimize foam stability. Although multiple chemistries have been used as foam inhibitors, there are two major categories in most industrial lubricants.

Silicone-Based Antifoam Agents (Polydimethylsiloxane or PDMS)

Silicone-based antifoam additives or silicone oil dispersions exist in lubricant formulations as finely dispersed droplets. These droplets are typically about 5 microns in size and offer efficiency at low concentrations. However, in close-tolerance or high-pressure systems that require clean fluids, silicone antifoam agents are susceptible to filtration. This is why we no longer see this additive used in hydraulic or turbine applications.

Have you ever noticed that when you rapidly fill up a soda in a convenience store, there’s seldom foam? Even though the same soda will create all sorts of foam when you open a can or bottle? This is because soda dispensing systems also inject a small amount of PDMS foam inhibitor into the carbonated water or syrup line. It’s incredibly effective, just like it is in a lubricant, as long as it’s not filtered out.

The second challenge with silicone foam inhibitors is their adverse reaction to the fluid’s air release properties. In 1982, the German Utility Industry published a document warning, “Although there are silicone additives which suppress the foaming tendency, caution is advised when using them, as these additives often have a very unfavorable effect on the air release value”.

Polyacrylate Defoamers

Polyacrylate defoamers have a lesser impact on the surface tension of the fluid compared to silicone foam inhibitors. Although they may not be as effective at reducing foam, they have a much less severe impact on air release properties. They are also more soluble in the fluid and, unlike silicone foam inhibitors, cannot be removed through filtration. This is the technology of choice in applications where clean oils and low air release values are desired.

Measuring the content of silicone foam inhibitors can be done by elemental spectroscopy. However, if dirt or sealant enters an in-service oil, assessing the foam protection by elemental spectroscopy is impractical. Unlike silicone foam inhibitors, directly measuring the health of silicone foam inhibitors for in-service lubricants is not practical for commercial oil analysis labs.

Practical Solutions for Foam Management

Managing foam can be a challenge. Determining the root cause of foaming is always preferable, starting with a diagnosis of whether it is a chemical or mechanical issue. However, even after extensive testing, the cause of high foam levels may remain unclear.

Below are a few suggestions on different strategies that can be effective.

Operational Optimization: Reservoir design improvements, such as enhanced baffling to ensure sufficient dwell time for air separation. System venting and deaeration can be effective.

Filtration: Removes contaminants that stabilize foam. Be sure to use filters rated at 5 microns or higher when filtering oils with silicone-based foam inhibitors.

Proactive Maintenance: Regular fluid-level checks will help maintain the fluid at the recommended level, minimizing agitation. Sealing integrity checks to prevent external air ingress.

Keep Systems free of Sludge and Varnish: Regularly test for varnish using tests such as the MPC test (ASTM D7843). Consider using a varnish mitigation system or solubility-enhancing technology to provide long-term protection from deposits. This will help minimize foam.

Strategic Antifoam Additive Management: In some cases, with sufficient upfront testing, the addition of antifoam agents may provide temporary relief. This should be considered carefully, along with sufficient laboratory simulation testing and the involvement of lubricant formulation experts in the process.

Real-World Case Study: Risks of Antifoam Additive Mismanagement

A power plant recently had a foaming issue in its turbine oil, as can be seen in Figure 3.

The power plant performed the D892 foam test, revealing that it exceeded the suggested critical limit of 450 mL. The original foam and air release values are shown in Figure 4.

The power plant added silicone foam inhibitor to the turbine oil. (Even though this foam inhibitor chemistry is not recommended by turbine OEMs.) However, the impact on the fluid’s air release values was significantly more severe than the original foaming issue, creating an even greater operational risk and rendering the oil unusable.

Although treating foaming fluids with tank-side additives can sometimes be effective, caution should be exercised before attempting to do this on-site, including extensive upfront testing.

Final Takeaways

Lubricant foaming poses a significant challenge, affecting lubrication efficiency, equipment performance, and operational safety. Armed with insights into foam mechanisms, robust testing methodologies (ASTM D892, ASTM D6082, ISO 12152), and informed additive selections, one can deploy effective foam-management strategies.

Strategic system design, meticulous additive management, proactive maintenance, minimizing varnish deposits, and informed oil analysis form the foundation for mitigating foaming, safeguarding equipment reliability, and extending operational life. 

References

1. ASTM D892 – Standard Test Method for Foaming Characteristics of Lubricating Oils.
2. ASTM D6082 – Standard Test Method for High Temperature Foaming Characteristics of Lubricating Oils.
3. ISO 12152:2002 – Lubricants — Determination of foaming and air release characteristics of lubricating oils — Flender foam test
4. DIN 51566 – German Standard for Foaming Characteristics of Lubricating Oils.
5. Bhushan, B. (2013) – Introduction to Tribology. Springer.
6. Totten, G. E., Westbrook, S. R., & Shah, R. J. (Eds.) (2017) – Fuels and Lubricants Handbook: Technology, Properties, Performance, and Testing. ASTM International.
7. Verlags – und Wirtschaftsgesellschaft der Elektrizitätswerke M. B. H. (VWEW), (1982) Stresemannallee 23, 6000 Frankfurt/Main, ISBN-3-8022-0045-4 (Translated from German)

A critical property of turbine oil is its ability to separate from water, known as its demulsibility characteristic. This property is essential for protecting turbine components from inadvertent damage to viscosity changes or corrosion. Water and oil are immiscible due to their distinct chemical natures.

The principle “like dissolves like” explains this phenomenon: water molecules are polar, possessing an electronegative oxygen atom and electropositive hydrogen atoms, while oil molecules are non-polar, lacking strongly electronegative or electropositive atoms.

Oil and water don’t mix – unless demulsibility fails.

When mixed, water molecules tend to agglomerate rather than mix with the organic hydrocarbon molecules, causing water to be rejected from the oil. Oil floats on water because its molecules are larger and significantly less dense. However, when an oil loses its demulsibility characteristics, a cloudy emulsion is formed, as seen in Figure 1.

Measuring Demulsibility Using ASTM D1401 (ISO 6614)

The ASTM D1401 test method is widely used to evaluate an oil’s demulsibility. In this procedure, a 40 mL sample of the oil is mixed with 40 mL of distilled water (or synthetic seawater) in a graduated cylinder. The mixture is stirred for 5 minutes at 54°C. For oils with a viscosity greater than 90 cSt at 40°C, the test can also be conducted at 82°C. An example of the graduated cylinder at the conclusion of the demulsibility test can be seen in Figure 2.

The separation time of the emulsion is recorded at specified intervals, typically every 5 minutes, or at a predetermined time limit. If complete separation or reduction of the emulsion to 3 mL or less does not occur within 30 minutes (or another specified time limit), the volumes of oil, water, and emulsion remaining are documented.

For instance, a result of 40-40-0 (20) indicates that after 20 minutes, complete separation was achieved, resulting in 40 mL of oil, 40 mL of water, and 0 mL of emulsion. This can be seen in Figure. 3.

Factors Leading to Poor Demulsibility Performance

Turbine oils can dissolve small amounts of water, referred to as dissolved water, typically holding about 100-150 ppm at room temperature. The presence of polar-heteroatom hydrocarbon species in the oil significantly impacts water separability. In-service turbine oils may fail demulsibility tests due to polar constituents, allowing water to become miscible in the oil.

Even minimal amounts of polar molecules can severely affect demulsibility, depending on their polarity and chemistry. For instance, a laboratory study by ExxonMobil indicated that calcium levels as low as 3 ppm, in the form of calcium alkylbenzene sulfonate, can impact demulsibility values.

Field tests have shown that even smaller concentrations can be problematic, making identifying the root cause of demulsibility failure challenging. Occasionally, oil analysis can pinpoint a root cause, such as the presence of calcium. However, in most cases, the material present is too minimal to be identified through conventional analysis methods like FTIR or ICP spectroscopy.

Polar constituents enter turbine oil either through fluid contamination or fluid degradation.

Fluid Contamination

Contaminants can enter the turbine oil system through various means:

• Oil top-offs, introducing contaminants and new additive chemistries
• Maintenance activities, such as flushing, which introduce detergents or cleaners
• Air ingression, carrying contaminants into the fluid
• Water and steam leaks, polluting the oil with water and its treatment chemistries

Alkylbenzene sulfonate detergents are common contaminants that may remain in the turbine oil system after a flush. This chemistry adheres to metal parts during cleaning, making it difficult to remove and destroy demulsibility at very low concentrations. The molecule’s structure, with a strongly polar sulfonate head and a non-polar alkyl-benzene tail, allows it to combine water and oil phases. Higher component concentrations result in poorer demulsibility.

Even trace contaminants can destroy oil’s ability to shed water.

Steam turbines are prone to seal leaks and moisture ingress. While the ingress of high-purity water can lead to various performance issues, it does not directly affect demulsibility characteristics. However, the water is treated with corrosion-preventing chemicals such as boric acid, lithium hydroxide, and hydrazine.

Chemicals like sulfite are added to eliminate dissolved oxygen, and phosphate compounds are used to control pH and prevent scale formation. These polar chemicals can adversely impact the demulsibility characteristics of turbine oil.

Fluid Compatibility

Fluid compatibility is measured by the interaction of fluid components. Antagonistic interactions first affect interfaces—air/fluid (foam), solid/fluid (MPC or haze), and water/fluid (demulsibility). Factors affecting compatibility include fluid mixing, improper flushing, and formulation changes, which alter the fluid’s polarity and surface polarity.

Increased fluid polarity enhances the interaction between polar water molecules and the fluid, affecting demulsibility. Ingress chemistries with polar-head/hydrocarbon-tail functionality or internal polarity can similarly impact fluid polarity.

Fluid Degradation

Thermal and oxidative stress on turbine oils produce degradation products, known as soft contaminants, which are polar and can be measured by the MPC test (ASTM D7843). Oil degradation is commonly believed to be the primary reason for diminishing demulsibility characteristics.

This makes logical sense since degradation products are polar, and the introduction of polar constituents to the oil causes demulsibility characteristics to fail. However, in practice, this relationship may not be accurate. We analyzed the data from 350 used turbine oil samples to measure the correlation between the mL of emulsion from D1401 and the DE value from D7843, as seen in Figure 4.

Demulsibility failures are often caused by contamination—not degradation.

The correlation between MPC and emulsions was 0.06. If there were a perfect correlation, this value would be 1, or if there was a perfect inverse correlation, -1. A value of 0.06 means there is no correlation whatsoever.

Addressing Failing Demulsibility in Turbine Oils

When evaluating oil analysis results, the most critical step is taking appropriate action. Common questions that arise include:

• What corrective action is required based on these results, if any?
• Is there any indication of a sampling error or lab error?
• Should I adjust my sampling intervals based on these results?
• What are the implications of not taking action?

According to ASTM D4378 (Standard Practice for In-Service Monitoring of Mineral Turbine Oils for Steam, Gas, and Combined Cycle Turbines), action is recommended when there are ≥3 mL of stable emulsion after the demulsibility test. The guideline suggests several actions:

• Identify and eliminate the source of contaminants.
• Clean the system using adequate filtration techniques.
• Consider an oil change if water separability cannot be restored.

However, making an informed decision involves more than just following these guidelines; operational risk must always be considered.

There are numerous instances where turbine oil is replaced due to failing demulsibility, despite all other parameters being within acceptable limits. Often, the new oil also fails demulsibility shortly after the change, leading to unnecessary expenditure of resources.

Turbine oils can fail demulsibility tests and still perform reliably for years.

Poor demulsibility properties in turbine oil do not inherently indicate an operational risk. Turbine oils can still deliver excellent performance for years, even with failing demulsibility values. The risk arises only when water enters the oil, potentially affecting its viscosity and separation properties.

Even then, failing demulsibility may not pose an additional risk to the turbine. For gas turbines, water ingress is rare and typically evaporates quickly. For steam turbines, effective water removal can mitigate operational risks.

Failing demulsibility should be considered a condemning criterion if the application is prone to water ingression and there are no suitable water removal technologies available. The flow chart in Figure 5 illustrates this decision-making process.

To ensure the effective removal of water from turbine oil with compromised demulsibility, it is crucial to employ advanced water removal technologies. Specifically, the utilization of a modern coalescer or vacuum dehydration system is recommended. Older methods, such as centrifuges or polymeric filters, are inadequate for eliminating dissolved or emulsified water, as demonstrated in Table 1.

Like with any oil analysis test slate, the data point from one test data cannot be viewed in isolation. If turbine oil demulsibility is poor, viewing other oil analysis data may help determine the reason why. Additional testing will help you to better assess the overall condition of the fluid allowing more informed decisions.

In conclusion, the demulsibility characteristic of oils is a critical factor in maintaining the operational integrity and longevity of turbine systems. The ability of turbine oil to separate from water is essential for preventing viscosity changes and corrosion, which can lead to significant damage and operational risk.

Poor demulsibility does not inherently indicate an operational risk, but it becomes a concern when water ingress is likely and suitable water removal technologies are not available. By employing modern water removal techniques, like vacuum dehydration, and understanding the factors affecting demulsibility, operators can make informed decisions to ensure the reliability and performance of their turbine systems.

Whether we realize this or not, oil refineries are critical in our everyday lives. They convert crude products into diesel, gasoline, LPG, and plastics. The equipment in this plant must withstand very high temperatures, sometimes over 500°C (in the distillation unit).

The lubrication systems in these plants also must withstand very harsh environmental conditions. Quite often, the bearing temperatures in critical compressors may increase to over 100°C, threatening a trip or shutdown. Unplanned downtime reduces refinery output and may cost a refinery up to Euro 1.2 M/day. All of this can be avoided by maintaining the quality of the lubricants.

Why Varnish Threatens Refinery Operations

Varnish, lubricant-derived system deposits occur in most types of equipment. It plates out as deposits on the insides of the equipment, which will act as a thick layer of insulator, preventing heat from escaping. One of the main functions of oil is to provide cooling to the equipment by transferring heat away from the internals of the equipment. However, with the formation of varnish, this function of the oil is eliminated.

Essentially, varnish can be described as polar compounds that have been formed as a result of the degradation of oil. There are various ways in which oil can degrade to produce deposits. As such, varnish can have varying characteristics depending on the system’s conditions, the formulation of the oil, and any contaminants that may be present in the system.

Despite the way varnish was created, some aspects remain the same. The presence of varnish can cause the sticking of valves or impact the efficiency of heat exchangers. Given the small clearances for hydraulic or other precision equipment (such as turbines or in bearings), any deposits inside these components can affect oil flow.

This results in elevated temperatures, which further increase thermal stress on the oil, thereby establishing a continuous feedback loop.

Varnish buildup creates a feedback loop of rising temperatures and increased stress on oil.

According to the varnish lifecycle illustrated in Figure 1, varnish can precipitate in and out of the solution even after oxidation has occurred.

From this lifecycle, it is clear that the double arrows are used between the solubility and varnish formation stages. As such, even if varnish is formed and deposited using the right technologies, it is possible that it can be redissolved into the oil.

In compressor applications, its bearings are the most critical place for varnish to form. This occurs in the minimum film thickness zone, as seen in Figure 2.

As per (Jang, Khonsari, Soto, & Livingstone, 2024), one can predict the effect of varnish on bearing performance by solving the Reynolds equation for pressure distributions with the mass conservation algorithm coupled with the energy equation through viscosity. However, this method was not utilized at the refinery.

Based on the study by (Jang, Khonsari, Soto, & Livingstone, 2024), the maximum pressure decreases when the varnish size extends circumferentially at a given varnish thickness, but the temperature remains relatively constant.

Case Study: How TÜPRAŞ Tackled Varnish Issues

Tüpraş is Turkey’s largest oil refiner, and it is located in western Turkey. It manufactures LPG, gasoline, jet fuel, and diesel fuel. They experienced trips on their compressor in the Kırıkkale Refinery, which has a mid-level complexity by Mediterranean Standards, including hydrocracker, isomerization, diesel sulphurization, and CCR reformer units.

The Kırıkkale Refinery has an annual crude oil processing capacity of 5.4 M tonnes, and its supply is carried by the BOTAȘ’ Ceyhan Terminal and Ceyhan- Kırıkkale pipeline. It was established in 1986 to meet the petroleum demands of the Ankara, Central Anatolia, Eastern Mediterranean, and Eastern Black Sea regions.

The K1151 compressor (RB5B Thermodyne compressor) in the Kırıkkale Refinery is critical to the Crude oil processing and isomerization unit. Every time this asset trips, the facility undergoes maintenance and repairs, typically lasting seven business days. This issue may occur at least 4 times annually, and each trip costs roughly around USD274k per event.

A trip usually occurs when the bearing temperature goes above 115°C, however, based on the history of the machine, the temperatures typically see a spike to 100°C followed by a rapid increase to 115°C.

For this compressor, it was also noticed that there were sawtooth-like temperature patterns where the values fluctuated between 76-86°C, as shown in Figure 3 below. The “safe zone” of operation for the bearings is less than 89°C.

This sawtooth temperature pattern is typically seen in instances where there is varnish buildup on bearings or shafts. Usually, the varnish builds up layer by layer, acting as an insulator, which causes the temperatures to increase.

Eventually, the buildup will get to a point where the shaft wipes away the varnish, resulting in a plunge in temperature, forming this sawtooth pattern. This repeats constantly until the varnish is either removed from the system or shut down so it can be removed.

After dismantling the NDE (Non-Drive End) bearing, varnish was found along the shaft and the actual bearing, as shown in Figures 4 and 5 below.

Interestingly enough, the bearings gave different temperature readings for this component. TI 633 showed slightly different readings compared to TI 632 mainly because of where they are positioned on the bearing, as these pads had varying levels of varnish on them, as shown below in Figure 6.

The refinery elected to add Fluitec’s DECON to the system during operation to provide immediate temperature relief to the bearing. DECON enhances the solubility of the oil, which does two things:

1. It dissolves varnish throughout the system, and in this case, specifically in the bearings and shaft.
2. It prevents future varnish from forming again.

Solubility enhancers are soluble in the oil and can react with already degraded products (deposits or varnish) to make them soluble in the oil. In this way, the degraded products are not allowed to agglomerate into the layers of deposits and remain in the oil as inert, harmless products.

After Fluitec’s DECON was added to the system, the compressor saw an immediate decline in temperature from 101°C to 93°C and continued to decline afterward. Currently, this bearing is operating in the temperature range of 63°C. The highest temperature experienced by the system is 73°C, which is significantly below their “safe-zone” temperatures of 89°C.

After adding DECON, compressor bearing temperatures dropped from 101°C to 63°C.

Since adding DECON to their system, they have not had any other trips due to rapid temperature increases, and their bearings now operate below the maximum threshold temperature range.

Tüpraş is committed to sustainability and aims to be carbon-neutral by 2050. The company focuses on innovative technologies and digital transformation to enhance operational efficiency and reduce carbon emissions. DECON is consistent with their organization’s objectives as it significantly improves compressor efficiency while increasing operational reliability.

Using Fluitec’s Value Impact Calculator, it is estimated that 32 tons of CO2e will be reduced from their operation over 5 years simply by optimizing the life and performance of their lubricant.

References

Jang, J. Y., Khonsari, M. M., Soto, C., & Livingstone, G. (2024). Effect of varnish on the performance and stability of journal bearings. Tribology International, Volume 198.

Heat Transfer Systems (HTS), also known as thermal fluid heating systems or hot oil systems, operate by circulating a fluid through a closed-loop system to transfer heat to and from various process equipment. These systems are widely used in industries for applications requiring precise temperature control and high-temperature operations without the need for high pressure.

Heat transfer oils are formulated for long service life and to resist thermal cracking and oxidation. Eventually, they will deteriorate, generating deposits that may interfere with the system’s heat transfer efficiency. Remedying these efficiency losses and system deposits involves a costly system shutdown and complex flushing processes.

A new maintenance approach has been developed to restore system efficiency and improve lube oil quality without requiring an outage. We will review the science behind this innovation and present a case study demonstrating its effectiveness.

Heat Transfer System Basics

HTS are simple in design and consist of a heater, pump, expansion tank, and process vessel. The components are shown in Fig. 1 below.

Understanding the bulk oil temperature can help estimate the thermal stress placed on the oil. However, there are also higher thermal loads placed on the fluid at the interface of the piping as the oil flows are lower in this region, as can be seen in Figure. 2.

In a properly functioning HTS utilizing hydrocarbon oil heat transfer fluids, the oil film is typically 14-28°C (25-50°F) higher than the bulk oil temperature. However, if the oil velocity is reduced, film temperatures can be more than 40°C (104°F), causing accelerated oil degradation. Well-established calculations are used to estimate film temperature based on oil flow, pipe diameter, and heater capacity.

Conventional heat transfer oils thermally crack at 360°C (680°F), so understanding the fluid film temperature is essential to fully understand the oil’s thermal stress.

Thermal Fluid Degradation and Analysis

Mineral-based heat transfer fluids can degrade in two main ways: thermal cracking and oxidation. Thermal cracking involves breaking the bonds between carbon atoms and forming shorter hydrocarbon molecules. This happens more often in closed HTS systems that may have nitrogen blanketing.

Oxidation involves transferring an electron from one molecule to another, increasing its oxidation state. This happens more often in open systems that have contact with air.

Even though the two oil degradation mechanisms are due to high temperatures, the impact on the oil differs depending on which pathways are involved. Table 1 illustrates the differences between the two phenomena.

To determine the condition of in-service heat transfer fluids, Mobil has developed an oil analysis package that includes the following tests:

• Viscosity
• Water volume % Karl Fischer (KF)
• Oxidation
• Total Acid Number (TAN)
• Particle Quantifier (PQ) Index
• Metals
• Flash Point (Cleveland Open Cup)
• Micro Carbon Residue (MCR)

Other tests may include Flash Point (Penske Martin Closed Cup), Conradson Carbon Residue, Pentane Insolubles, or Simulated Distillation by Gas Chromography.

Assessing Fluid Safety

Thermal cracking breaks the backbone of hydrocarbon molecules. The newly created, smaller chain molecules lower the viscosity and flash point of the oil. Flash point testing is essential because safety risks are introduced to the system if it falls too low.

The first screening is the Cleveland Open Cup flash point test (ASTM D-92). If it has not decreased, thermal degradation is not a significant influence. However, further testing is warranted if the flash point has dropped to more than 50°C (122°F). The Penske-Martins Closed Cup flash point test (ASTM D-93) concentrates the light ends or low boilers produced through thermal cracking.

It is not uncommon to see 100°C (212°F) differences between flash point testing methodologies, with ASTM D-93 delivering a lower flash point result when light ends are prevalent.

It’s important to ensure the closed-cup flash point of in-service oil is at least 14°C (57°F) above the temperature of the oil exposed to air (i.e., an open expansion tank). Values lower than this are typically considered critical, as the oil’s flash point approaches the exposed oil temperature, the chances for ignition or fire increase.

Flash point testing is an important parameter, but it only measures the presence of light ends, not their concentration. To get deeper insight into the degree of thermal degradation and estimated remaining useful life of the oil, one can employ Simulated Distillation by Gas Chromatography (GCD).

This test measures the relative proportions of the entire range of molecules in the sample and provides a deeper understanding of the thermal stress on the fluid. An example can be seen in Figure 3.

Degraded Oils Impact HTS Efficiency

Measuring efficiency in a Heat Transfer System involves evaluating how effectively the system transfers heat without incurring unnecessary energy loss. Here are key factors and methods used to measure efficiency:

1. Thermal Efficiency: This measures the ratio of heat transfer effectiveness of the hot oil system to the energy input. It can be calculated by comparing the heat transferred to the process to the total energy supplied to the hot oil heater.
2. Temperature Differential: Monitoring the temperature differential between the inlet and outlet of the process equipment can indicate how effectively the hot oil system is transferring heat. A smaller differential may indicate heat loss or inefficiency in the system.
3. Flow Rate: The flow rate of the oil through the system impacts heat transfer efficiency. Too low a flow rate can lead to inadequate heat transfer and accelerated oil degradation, while too high a flow rate can increase energy consumption without proportional benefits. Measuring and optimizing flow rates are crucial.
4. Pump Efficiency: Since pumps are used to circulate the hot oil, their efficiency impacts the overall system efficiency. Measuring the electrical energy input to the pump and comparing it to the hydraulic energy delivered by the pump can indicate its efficiency.

Sufficient thermal stress on heat transfer fluids over a long enough time will cause even the most highly refined products to degrade. One of the failure mechanisms of these fluids is the formation of carbon-rich deposits. The formation of oil deposits can lower HTS efficiency in each of the above four areas.

The Challenge with Treating Thermal Fluids

Shutting down heat transfer systems for maintenance can be costly as their operation is tightly linked with production. Furthermore, in badly degraded systems, the oil may solidify, requiring shovels or even the removal of piping to evacuate the deposits.

Online remediation of thermal fluids in heat transfer systems is also challenging, stemming from the need to maintain system efficiency, safety, and integrity without disrupting the production process. Here are some of the key challenges:

• Safety Concerns: Handling hot thermal fluids poses significant safety risks, including burns, fires, and explosions. Performing online remediation requires stringent safety protocols to protect personnel from the hazards associated with high temperatures and potentially reactive or flammable fluids.
• Decontamination: Advancements in chemical filtration technologies to remove oil degradation products in other industrial lubricant applications are not suitable for heat transfer fluids due to the high temperatures.
• Detergent-based oil cleaners: Adding chemical cleaners to heat transfer fluids may be a suitable strategy when part of a turnkey flushing procedure but introduces operational risks when added to an operating system, including rapid deposit accumulation and decreased flash points.

Mobil™ Solvancer® is an Online Solution to Improve System Efficiency

Mobil Solvancer is a full synthetic, API Group V, oil soluble cleaner designed to be safely added to in-service oils with no measurable impact to fluid quality or system performance. It dramatically increases the solubility of an in-service oil allowing deposits to be dissolved. It also minimizes further deposits from being generated.

Mobil Solvancer helps to eliminate carbon deposits from heat transfer systems, making heat exchangers, pipes, and pumps cleaner. Mobil Solvancer is an effective solution to increase system efficiency in HTS by tackling carbon deposits.

Case Study: Improving System Efficiency in an Asphalt Plant

Inefficiency was slowing production at a US-based asphalt plant. Their HTS failed to consistently maintain thermal balance, causing increased labor costs and component wear. To improve plant thermal efficiency, the plant added 3.3% Mobil Solvancer to the in-service heat transfer fluid.

Figures 5 and 6 show the Mobil Solvancer being added to the HTS as well as the appearance of Mobil Solvancer.

After more than six months, the plant observed numerous benefits, including*:

• 20% decrease in fuel consumption.
• Increased plant capacity and flexibility with longer production runs.
• Decreased trucking expenses to deliver binder.
• Zero hot oil breakdowns (for the first time in the plant’s history).
• Reduced pump wear due to less direct heating.
• Restored thermal balance measured after a few weeks resulting in faster start-ups.
• Lower maintenance costs to restart the system, as previously, crews would have to manually heat pumps and injection pipes.
• Reduced oil consumption as the system’s overall oil parameters were stable enough to allow the plant to skip a full system oil change.
• The micro carbon residue (MCR) deposit test and viscosity showed improvements with no change to the fluid’s flash point.

*Individual results may vary depending on operating and weather conditions

Heat Transfer Systems exert sustained, high heat stress on their thermal fluids, resulting in the formation of carbon-rich deposits. The accumulation of these deposits lowers the efficiency and thermal balance of HTS. Traditionally, treating in-service heat transfer oils is challenging due to safety and system performance concerns. Mobil Solvancer represents a novel way of treating in-service heat transfer fluids, restoring system efficiency.

A case study in an asphalt plant was presented, which demonstrated that Mobil Solvancer restored thermal balance in their system and reduced fuel consumption by 20%. The quality of the in-service oil was also improved, avoiding an oil change.

Please contact your local Mobil or Fluitec technical specialist for specific details about adding Mobil Solvancer to your thermal fluid heating system.

 © 2024 ExxonMobil. All trademarks used herein are trademarks or registered trademarks of Exxon Mobil Corporation or one of its subsidiaries. All rights reserved

© 2024 Fluitec. Fluitec and Solvancer are registered trademarks of Fluitec NV or one of its subsidiaries.

Varnish is characterized as a deposit originating from the degradation of lubricating oils. These degradation byproducts are predominantly polar compounds, exhibiting inherent instability within the non-polar phase of the lubricating oil. Due to this chemical incompatibility, they precipitate out of the oil solution, forming adhesive deposits on machine components.

The presence of varnish poses several reliability challenges in mechanical systems. For instance, these deposits can adhere to the internal surfaces of valves, resulting in increased friction and a propensity for the valves to adhere to their seats.

This sticking phenomenon disrupts the precise control of turbines, potentially leading to erratic operation and increasing the risk of unintended shutdowns, referred to as trip events.

Additionally, the accumulation of varnish on the surfaces of heat exchangers significantly impairs their thermal efficiency. The insulating nature of these deposits hinders optimal heat transfer, thereby reducing the overall efficiency of the heat exchanger system.

Oil degradation products also tend to form on bearings, causing many deleterious operational issues. This varnish is typically hard and tenacious and can harm the bearing’s performance.

It can restrict oil flow, reduce heat dissipation, and increase friction and wear. The high temperatures of journal and thrust bearings not only accelerate oil degradation but also facilitate the hardening of these degradation products on the bearing surfaces, further accelerating deposit formation.

This article focuses on the impact of bearing deposits, the mechanisms that cause them, detection methodologies, and remediation strategies.

How Deposits Impact Bearing Performance

Oil degradation products are also well known to form on bearings, causing many deleterious operational issues. This varnish is typically hard and tenacious and can be detrimental to the bearing’s performance in three main ways:

1. Act as an insulator – one of the main functions of an oil is to keep the system cool. However, with the formation of the deposits, these can act as insulators trapping heat. Therefore, the oil can no longer cool the bearing, leading to increased bearing temperature trends. This can also lead to rapid bearing temperature excursions, causing trip alarms and potentially threatening operations.
2. Act as surface asperities – a bearing typically undergoes different phases of lubrication. Ideally, it should maintain a hydrodynamic film (complete separation of the two surfaces) to ensure its efficient operation. With the presence of these deposits in the high load areas, these surface asperities can interrupt the hydrodynamic film, causing the bearing to experience a mixed lubrication regime. In this condition, the bearing will have metal-to-metal contact between the two surfaces, resulting in wear or scoring, as shown in Figure 1 above.
3. Induce vibrations – The mechanical impact of bearing deposits may be sufficient to cause measurable vibrations in the bearings.

Characterization of Bearing Deposits

Two distinct types of bearing deposits form through different mechanisms, each with potentially different remediation strategies.

1. Cold Varnish Deposits: This category predominantly results from oil oxidation, a process where oil molecules react with oxygen, forming polar byproducts. The oxidative degradation pathway is explained in Figure 2.

   These oxidation byproducts are typically aldehydes and ketones, which are quite soluble in the oil. They may undergo aggregation and agglomeration, evolving into larger molecular structures with reduced solubility in the oil.

   This results in the formation of adhesive deposits. As the oil is squeezed through a bearing, it concentrates the amount of degradation products, leading to molecular cross-linking, further reducing the solubility of the degradation products, resulting in deposits.

Detection methodologies primarily include Membrane Patch Colorimetry (MPC, ASTM D7843) and Ultracentrifuge tests. These diagnostic tools are vital in providing early indicators of oil degradation presence and their potential to form deposits, enabling timely implementation of varnish removal and prevention strategies.

2. Shear Stress Deposits (Hot Varnish): This deposit type is distinguished from cold varnish by its formation mechanism and chemical composition. In this case, oil degradation is driven by mechanical forces, where mechanical energy is converted into thermal energy under high shear conditions. This process results in localized temperature spikes, predominantly observed in turbomachinery operating under high-speed and heavy-load conditions.

   The chemistry of these shear stress deposits differs markedly from those derived from oxidative processes as they have a higher concentration of less soluble fatty acids.

According to Chu Zhang (2017), the molecular friction generated from Shear Stress can result in temperatures reaching several hundred degrees Celsius, leading to instant degradation and the formation of localized deposits. Yulong Jiang (2021) also further explains that these high temperatures are isolated and localized in the minimum oil film thickness zone, which occurs at a molecular level.

The “Morton Effect” is a phenomenon of synchronous rotor instability due to non-uniform heating of journal bearings and is said to be caused by shear stress. The Morton Effect also causes vibration issues in turbomachinery. As per Jongh (Sep 17-20, 2018), shear stress is a dominant factor in generating non-uniform bearing temperatures.

Direct observation and temperature measurement of turbine oil during operational phases is impossible. The oil film, often only a few microns thick, precludes in-situ temperature monitoring at these scales. Nonetheless, analyzing bearing deposits can infer indirect evidence of high-temperature occurrences.

As illustrated in Figure 3 below, a bearing pad coated with varnish is examined. Samples of deposits extracted from various bearing regions underwent rigorous chemical analysis.

The findings revealed that the bulk of these deposits were organic, primarily composed of oxidized oil degradation byproducts. This chemistry contrasts with the darkest deposits, which exhibited an inorganic composition, predominantly consisting of phosphorus-based extreme pressure (EP) additives.

Under normal conditions, these EP additives remain inert, typically requiring activation temperatures around 200°C to react. The presence of these activated EP additives in the deposits strongly indicates the occurrence of localized high-temperature zones within the bearing system.

Such micro-temperature fluctuations are challenging to detect with conventional bearing thermocouple probes, underscoring the complexity of monitoring and diagnosing thermal dynamics in turbine oil films.

Primary Drivers of Lubricant Degradation Under Shear Stress

Shear Stress Degradation is influenced by the load exerted on the bearing and its rotational speed. The critical zone of maximum load within a bearing coincides with the region where the oil film attains its minimum thickness.

As illustrated in Figure 4, empirical observations corroborate that this zone of minimal oil film thickness is the primary site for the formation of deposits.

This correlation underscores the significance of these mechanical parameters in the onset and progression of shear stress-induced lubricant degradation.

It has been noted that Shear Stress deposit events occur with a greater frequency in compressors compared to turbines. This can be because the bearings in a compressor typically experience rotational speeds over 50,000 rpm.

On the other hand, the bearings in turbines usually operate at approximately 3,600rpm in the 60Hz North American market and 3,000rpm in the European and Asia Pacific markets at a frequency of 50Hz.

Detection Methods

Oxidatively derived cold varnish can be measured with the MPC or UC test as the bulk oil has experienced degradation. However, oil analysis tests are less valuable when an oil undergoes shear stress degradation.

Observing bearing temperature and vibration trends can detect shear stress deposits. Visual inspections of the bearings during outages are also valuable.

Typically, temperature spikes resembling a sawtooth-like wave pattern, as seen in Figure 5, are expected when varnish is present. A stable sawtooth waveform can also represent the presence of varnish.

Varnish has high film strength. In some cases, the accumulation of bearing deposits can move the entire shaft. Therefore, with systems monitoring the shaft position, utilizing the gap voltage vertical probe measurement will be worthwhile.

As shown in Figure 6 below, the shaft moves away from the center position as the temperature increases due to deposit accumulation. The shaft’s vertical position shift correlates closely with a bearing temperature spike.

Bearing temperature excursions can cause operational disruptions. Below are some noteworthy bearing temperatures based on API 670:

• 110° C Alarm Temperature
• 120° C Trip Temperature
• 132° C Babbitt Creep
• 232° C Babbitt melting point

How can Bearing Deposits be Mitigated?

Cold Varnish

Oxidatively-derived bearing deposits can be removed by installing a resin-based filtration system, such as Electrophysical Separation Process (ESP) technology.

It can also be prevented or removed using a solubility enhancer, such as DECON. The impact of these technologies results in bearing temperature decreases, low MPC values, elimination of bearing wear, and increased efficiency due to lower friction.

Figure 7 shows an example of a bearing in a steam turbine before and after an ESP system was installed.

Hot Varnish

Shear Stress Deposits have been observed in Group I, II, III, and IV base oil formulations. This suggests that simply changing the oil to another base stock formulation will not alleviate the issue. However, there are potential mechanical and chemical solutions.

Mechanical Solutions

From a mechanical aspect, Shear Stress Deposits can also be controlled by reducing the load on the oil. Some mechanical fixes include;

• Reducing the load (this is operationally feasible but reduces compressor output, making it a costly option)
• Expanding bearing clearances (Jongh, Sept 17-20, 2018)
• Offsetting the bearing pivot towards its lagging side has been proven to improve the angle of attack and allow more oil to flow
• Directional lubricating (Bloch, July 2006)

The Chemical Solution

Adding a solubility enhancer is a potential chemical solution to this mechanical problem. DECON has been shown to have an immediate impact on deposits and can lower the temperatures in bearings. It is an oil-soluble cleaner designed to be added at 3-5%.

It has been designed for long-term use, which can provide a permanent solution to bearing deposits. This product effectively mitigates deposit formation by enhancing the solubility of the in-service oil, enabling the dissolution of degradation byproducts.

Often, varnish products comprise depleted antioxidants, inorganic additives, and degraded hydrocarbon molecules. DECON is designed to soften the carbon-based deposits upon which the inorganic deposits (such as the aldehydes, ketones, and fatty acids found on journal bearings) usually adhere. Thus, when these carbon-based deposits soften, they can be easily removed.

When these deposits are dissolved into the oil, they remain inert and pose no operational concerns until they principate out of the solution. Dissolving these deposits back into the oil does not adversely impact the oil’s condition, nor does it pose a risk of catalyzing further degradation.

Figure 8 shows the temperature graph after adding 3% of DECON to a compressor suffering from shear-stress deposits. The temperature excursions stopped after a few hours.

Not all mechanical issues can be solved through chemistry. However, DECON is cost-effective for bearings experiencing shear stress and oxidatively derived deposits.

Summary of Differences Between Hot Varnish and Cold Varnish on Bearings

The following table summarizes the differences between hot and cold bearing deposits.

Summary

Bearing deposits can have a significant impact on the operation of rotating equipment. They lead to high bearing temperature excursions, wear, and increased friction. Two different types of deposits are found on bearings: oxidatively-derived cold varnish and Shear Stress-derived hot varnish.

The traditional methods of utilizing the MPC and UC (Ultracentrifuge) tests to detect the presence of cold varnish in equipment are ineffective in detecting hot varnish or shear stress deposits. By monitoring bearing temperatures and vibration, operators have an increased opportunity to detect the presence of shear stress deposits.

Bearing deposits experiencing cold varnish may be remedied by installing a resin-based filtration system, such as ESP technology, or adding a solubility enhancer, such as DECON.

The remedy to shear stress deposits is often a mechanical fix that may spread the bearing load over a greater oil surface to reduce load, especially in the minimum oil film thickness zone. Alternatively, DECON has been shown to be an effective chemical solution to shear-stress deposits.

 This is article is based on the white paper ” Understanding Shear Stress and the formation of deposits in heavily loaded, high-speed bearing applications” by Greg Livingstone (Fluitec) and Cody A. Evans (Mobil).

References:

1. Chu Zhang, J.-G. Y.-S. (2017). Influence of Varnish on Bearing Performance and Vibration of Rotating Machinery. International Journal of Rotating Machinery, Article ID 9131275, 10 pages.
2. Jongh, F. d. (Sept 17-20, 2018). The Synchronous Rotor Instability Phenomenon – Morton Effect. 47th Turbomachinery & 34th Pump Symposia, Houston, Texas, 12.
3. Yulong Jiang, B. L. (2021). Prediction on Flow and Thermal Characteristics of Ultrathin Lubricant Film of Hydrodynamic Journal Bearing. Micromachines, 12, 1208.
4. Bloch, H. (July 2006). Tilting Pad Thrust Bearings. Machinery Lubrication. July 2006.

Condition monitoring sensors for lubricants have been an established technology for numerous decades, playing a vital role in safeguarding some of the most essential machinery worldwide, including their incorporation into certain premium automotive models.

However, it is somewhat paradoxical that lubricants within rotary machines, such as turbines and compressors—equipment fundamental to electricity generation and numerous chemical and industrial operations—rarely utilize remote sensing for condition monitoring.

This discrepancy can be attributed to two primary factors. First, the longevity of turbine oils, particularly within older steam or hydroelectric turbines, has deemed quarterly oil analysis sufficient for tracking condition trends.

Second, the performance of sensors available to these applications thus far has demonstrated inadequate correlation with analytical laboratory results.

But the landscape is evolving. Modern gas turbines operate at higher temperatures, imposing unprecedented thermal stress on their lubricants. Compressor systems present an even more demanding scenario for turbine oils, contending with thermal challenges, contamination from external gases, and, in some instances, exceedingly high operational speeds.

Concurrently, there is a burgeoning requirement for remote monitoring capabilities that minimize the necessity for physical, on-site maintenance. Against this backdrop, the imperative for real-time oil condition monitoring is intensifying.

This document examines a new real-time turbine oil monitoring development that employs infrared spectroscopy. It further elucidates the capacity of this technological advancement to meet the escalating demand for sophisticated sensors in this space.

Why Turbines and Turbine Oils Fail

Oil condition monitoring serves three primary technical objectives:

• Monitoring Lubricant Degradation Trends: This involves systematically tracking the degradation and aging process of the lubricant over time, which is crucial for maintaining optimal lubrication performance.
• Detecting Machinery Health Deterioration: The analysis aims to identify any signs of machinery wear or failure, which can be inferred from changes in the lubricant’s properties or composition.
• Quantifying Contaminant Levels: This includes the measurement of both external contaminants (such as dirt and water) and internally generated by-products (like wear metals and varnish). These contaminants can significantly impact the functioning and longevity of the machinery.

Given these purposes, it becomes clear that a thorough understanding of both turbine operation and the failure mechanisms of turbine oils is fundamental to effectively determining oil condition monitoring strategies.

Turbine Failure Modes

The most common modes of failure for turbines[1],[2],[3] are:

• Creep and Fatigue – which are caused by high temperatures and stress cycles. These can cause deformation, cracking, loss of efficiency, weakening of metal components, and rupture of the steam turbine components.
• Oxidation and corrosion are the chemical reactions of metal components with oxygen and other environmental substances. Oxidation and corrosion can cause pitting, scaling, and erosion of the turbine blades and other parts, reducing their strength and durability.
• Erosion is metal components’ physical wear and tear by abrasive particles or fluids. Erosion can cause material loss, roughness, and damage to the turbine blades and other parts, affecting their aerodynamics and performance.
• Steam-path distortion and/or blade/nozzle mechanical damage is caused by foreign-object damage, solid-particle erosion, cracking, and moisture erosion. These can affect a steam turbine’s flow, efficiency, and performance.
• Babbitt bearing failures, which are caused by babbitt fatigue, babbitt wiping, babbitt flow, foreign particle damage, varnish build-up, electrostatic discharge damage, electromagnetic discharge damage, oil burn, loss of bond, chemical attack, pivot wear, unloaded pad flutter, and cavitation damage. These can affect the alignment, stability, and vibration of the turbine.

Most turbine failure modes are not readily identifiable through oil sensor analysis, except for bearing health assessment. To effectively monitor the condition of turbine bearings, it is essential to employ sensors, including:

1. Temperature Probes: These devices measure the temperature of the bearing, which is a critical parameter. Elevated temperatures can indicate excessive friction, shear-stress degradation, misalignment, or lubrication issues, all precursors to bearing failure.
2. Vibration Sensors: These sensors detect and analyze vibrations emanating from the bearings. Variations in vibration patterns can signal issues such as imbalance, misalignment, bearing wear, or other mechanical faults.
3. Analysis of Varnish Potential in Oil: Assessing the potential for varnish formation in the oil is crucial. Varnish can be deposited on bearing surfaces and other critical components, leading to operational inefficiencies and potential failure.

Integrating these monitoring techniques can achieve a more comprehensive understanding of bearing health within turbines.

Turbine Oil Failure Modes

The primary cause of degradation in turbine oils is oxidation, although various other degradation mechanisms also play a role[4].

To assess the physical and chemical alterations occurring in turbine oil as a result of oxidative stress, the Turbine Oil Performance Prediction (TOPP) test is employed. This test measures how turbine oils change and deteriorate under oxidative conditions[5].

An example of a 12-week TOPP test can be viewed in Figure 1. Throughout the test, one can observe a rapid drop in phenolic antioxidants.

The amine antioxidants deplete similarly to the oxidative stability measured by RPVOT. Throughout the test, increasing MPC values show a high propensity for the oil to develop deposits. When selecting an appropriate sensor technology, considering turbine oil failure modes is essential.

An Oil-related, Catastrophic Failure Mode in Some Gas Turbines

A rare yet severe failure mode linked to turbine oil degradation has been observed in industrial gas turbines. This issue arises when the antioxidants within the turbine oil are exhausted, yet the oil continues to be used.

The situation becomes critical when an additional catalytic factor contributes to the chemical reaction. Under these conditions, the oil may undergo a process known as condensation polymerization, leading to the formation of long-chain cyclic compounds enriched with esters and acidic components.

The consequence of this chemical change in the oil is a dramatically accelerated degradation rate, which can be identified by increased deposits and an exponential rise in viscosity and acidity.

For the turbine, this scenario typically results in bearing failure and coating all oil-wetted components within the system with a highly adhesive and tenacious deposit. This deposit can significantly impair the turbine’s performance and necessitate extensive maintenance or repairs.

An example of trend analysis from this failure mode can be viewed in Figure 2.

Sensor Selection

The market offers diverse sensor technologies, each delivering distinct value across different applications. The selection of an appropriate sensor necessitates a thorough analysis of both the lubricant’s failure modes and the operational characteristics of the machine.

It’s important to note that sensor technology may be highly beneficial in one context yet offer minimal value in another.

Consider the following examples:

• Inline Viscosity Sensor: This sensor is particularly valuable in methane screw compressors, where gas ingression can cause rapid decreases in viscosity. In contrast, its utility is limited in turbine applications, where viscosity changes are uncommon. For instance, regarding the oil degradation previously discussed (Fig. 4), monitoring antioxidant health or detecting water ingression would be more predictive measures than tracking viscosity changes.
• Chip Detector: A chip detector can be an early warning indicator of impending engine failure in a fighter jet. However, its value is significantly reduced in steam or gas turbines. Wear metal formation is infrequent in these applications, and installing sensors directly downstream of each bearing for chip detection is logistically complex and often impractical.

Infrared Spectroscopy

The sensor platform developed by Spectrolytic utilizes the powerful analytical technique of mid-infrared spectroscopy to measure various relevant degradation parameters in an oil sample.

With each measurement, the sensor determines the changes in the oil at a molecular level using the same analytical technique and data extraction employed by oil laboratories worldwide.

The laboratories conduct an oil analysis on customer samples by applying various ASTM and/or DIN standards to determine Oxidation, Nitration, Sulphation, additive changes, and oil contamination levels.

This common baseline of using mid-infrared spectroscopy as the analytical tool not only allows the sensor to provide real-time data with the same units and accuracy as the oil laboratories, but it also provides the option to predict more complex oil parameters such as Total Acid Numbers (TAN), Total Base numbers (TBN) or ipH.

Another factor that should be considered is the simplicity of generating calibration files for any given oil/application. We have developed and designed the systems to allow the customer to monitor most parametric data from the day of installation.

There is no need to have old oil samples, ship oil samples around the world, or age the oils artificially.

Spectrolytic’s sensor platform has been installed in many different applications such as power generation (natural gas and biogas engines, gas turbines), aluminum and steel processing, and marine application (Marine Diesel and EAL oils for thrusters), showcasing the versatility and accuracy of the mid-infrared sensor platform.

Figures 3 and 4 compare lab analysis and inline sensor data for a natural gas engine application. There is an excellent agreement between predicted sensor data and reference analysis, as shown in the plots below.

The plot also displays ‘rogue’ measurements from reference analysis that the sensor does not display. This is likely some error in sample taking or sample measurement.

The sensor, therefore, removes all human involvement from the oil analysis process as there is no sample-taking process, no storage/shipment required, and no lab technician needed to carry out the measurements.

The results are reliable and consistent with the reference analysis, providing customers with accurate, understandable, and actionable oil analysis data 24/7.

Today’s oil formulations are complex and depend primarily on the application (engine, hydraulic, gearbox, etc.) regarding the base oil and additive packages used.

Base oils from Group I-III are mineral oils (even though some Group III base oils are classed in terminology as ‘synthetic’), and Group IV (PolyAlphaOelfins) and Group V (PolyAlkyGylcol, Polyolesters, Phosphate Ester, siloxanes, etc.) are classed as synthetic oils.

Multiple degradation mechanisms happen in parallel once a lubricant is used in an application. Turbine oil degradation is depicted below in Figure 8.

For any sensor technology to provide accurate, meaningful, and actionable data, the respective sensor technology must be able to DIFFERENTIATE between the respective degradation mechanisms. It must be able to QUANTIFY each degradation mechanism.

Spectrolytic took on this challenge with the development of its FluidinspectIR™ product line. It is now possible to offer customers real-time oil analysis with lab-quality data. A summary of the oil degradation parameters that are accessible using the FluidinspectIR ™ product line is presented in Figure 6.

Apart from these more conventional parameters, it is often also possible to measure parameters that are not commonly reported in a conventional oil analysis report but might provide an interesting insight into a specific application.

One example is the emulsifier absorption by the lubrication gear oil following a water leak during steel production.

The FluidinspectIR™ sensor platform can be complemented with additional sensors, such as viscosity, optical particle counting, etc., to provide customers with a complete solution for their respective applications.

Turbine Application Case Studies

The following shows where a FluidInspectIR™ system has been installed on a gas turbine in Figure 10. Field results from this application over the last nine months show lab results that are indistinguishable from real-time sensor results.

In this instance, the customer aimed to track not only phenols, amines, and oxidation levels in their oil but also the concentration of Solvancer™, a product used to enhance solubility and provide long-term protection against varnish.

Figure 8 illustrates that the average Solvancer level is maintained at around 3.09%, with the ability to detect changes as small as 100ppm. The Solvancer concentration must be held at a specific concentration over time, and it is crucial to monitor this level accurately during the turbine’s operation.

The FluidinspectIR sensor monitors the overall oil condition remotely and can identify any changes in concentration, such as when new oil is added to the system.

The fresh oil would dilute the Solvancer, resulting in a noticeable decrease in its percentage, potentially accelerating the varnish production processes of the lubricant. Based on the observed drop in the Solvencer concentration, the customer can be advised to top up the required concentration to retain optimum lubricant protection.

The most innovative aspect enabled by accurate, lab-quality real-time data for turbine and/or other asset management applications is “The Power of Slopes.”

The FluidinspectIR provides a complete oil analysis every hour, which enables us to analyze the slopes for any given parameter rather than look at the absolute values, which is the status quo, using conventional oil analysis.

An example of a brand-new diesel engine that suffered extensive soot generation during operation is shown below. After 200 hours, the customer decided to change a crucial component in the engine, which was the suspected root cause of the soot problem.

At the same time (220h), the oil was also changed, as is evident by the drop in oxidation (red circle at the bottom image).

Comparing the slopes of the soot graph before and after the maintenance process, it is evident that the root cause of the problem was not the suspected part, as the slopes are identical. The sensor data provided this information after 40 operational hours.

The same approach is now being employed in turbine oils. Figure 13 displays a pattern where the oxidation rate in the turbine oil progressively increases across three oil change events. This trend could indicate a shift in the turbine operation or duty cycle.

However, it is more probable that the oxidation rate increased due to insufficient cleaning of the lubrication system between each oil change. Typically, the lifespan of oil is reduced by half if the cleaning between oil changes is not thorough, and the data presented in Figure 9 aligns with this understanding.

In the same way, the sensor data can now be used to ensure that any potential adverse effects related to an oil change are minimized, as the changes in the slopes will be evident even after a few days of operation.

Figure 11 illustrates a noticeable shift in the oil’s concentrations of phenols and amines. The in-service oil was a phenol-only formulation. However, the graph shows a significant decrease in phenol levels coinciding with a marked rise in amine levels.

This suggests that a new formulation, different from the original phenol-only composition, was introduced into the oil. This change can serve as an alert, allowing for a prompt investigation to confirm whether the addition was deliberate and whether the new formulation is compatible with the existing system.

Almost every turbine component is monitored in real-time, except for its lubricating oil. As the operational conditions of rotating equipment and turbomachinery evolve, there’s a reduction in on-site resources to support traditional lab-based condition monitoring.

This contrasts with the growing desire of central turbine engineers to get instant overviews of their entire fleet’s performance. These trends highlight the ever-increasing necessity for sensors that can provide real-time monitoring of the oil’s condition.

The first step in choosing a suitable sensor involves understanding the machinery’s and oil’s potential failure modes. For rotating equipment, the main concern is bearing health, particularly the oil’s tendency to form varnish.

Key changes to monitor in the oil include the depletion of antioxidants, corresponding reduction in oxidation stability, and an increase in oxidation, which leads to a higher potential for varnish formation.

Currently, mid-infrared technology is the only sensor capable of measuring these crucial failure modes. Notably, the data quality from these sensors matches that of laboratory tests, eliminating the need for new correlation studies to interpret the sensor data.

Spectrolytic’s FluidInspectIR has been effectively implemented in turbine settings, showing significant potential in fulfilling the increasing demand for accurate, affordable, real-time monitoring of some of the world’s most critical assets.

References

[1] Kazempour-Liasi, H., Shafiei, A. & Lalegani, Z. Failure Analysis of First and Second Stage Gas Turbine Blades. J Fail. Anal. and Preven. 19, 1673–1682 (2019). https://doi.org/10.1007/s11668-019-00764-1

[2] “Steam-turbine diaphragm repair strategies” https://www.ccj-online.com/steam-turbine-diaphragm-repair-strategies/

[3] John K. Whalen, Thomas D Hess Jr, Jim Allen, Jack Craighton. Babbitted bearing health assessment, Middle East Turbomachinery Symposium 2015.

[4] Mathura, S. “Lubrication Degradation Mechanisms (Reliability, Maintenance, and Safety Engineering),” CRC Press, 2020

[5] Livingstone, G., Rista, E. “How to Select Turbine Oils Strategically for Improved Results Now,” https://precisionlubrication.com/articles/select-turbine-oils/

The mention of lubricant varnish in an industrial setting frequently evokes concerns regarding unscheduled equipment shutdowns, reliability challenges, and consequent extended downtime. However, a facet that often remains overlooked is the concept of ‘solubility.’

This underpins an understanding of how degradation products interact with lubricating oils. The idea of solubility, although seemingly esoteric, is central to devising robust strategies for lubricant degradation monitoring and management, thereby preemptively addressing varnish-related challenges and promoting operational excellence.

Understanding Solubility

Solubility is a fundamental chemical property referring to the ability of a substance (solute) to dissolve in a solvent to form a homogeneous solution at a particular temperature and pressure. Various factors, including the nature of the solute and solvent, temperature, pressure, and the presence of other substances, govern the extent of solubility.

Understanding solubility is crucial in industrial lubrication, especially regarding the behavior of oil degradation products within lubricating oils. As oils age, they undergo oxidative degradation and thermal breakdown, generating various degradation products like acids, aldehydes, ketones, and varnishes. The solubility of these degradation products in the lubricating oil will impact the fluid’s performance. Therefore, a thorough understanding of solubility principles and their application can significantly contribute to effective lubricant degradation monitoring and management in industrial settings.

Is It Soluble or Insoluble?

Oil degradation products are often considered soluble or insoluble. However, solubility can only be defined when associated with a certain temperature. Labeling degradation products as either soluble or insoluble can be an oversimplification, creating confusion. To clear up some of the misnomers about solubility, here are a few things to keep in mind:

• Varnish is insoluble while a machine is operational. If it were soluble, it would go back into solution. This doesn’t mean that varnish can never be dissolved. For example, if you increase the in-service oil’s temperature or its solubility using a solubility enhancer, varnish may become soluble and be dissolved into the oil.
• Oil degradation products are soluble when you obtain an oil sample. Oil degradation products can come out of solution once the sample is stored at room temperature. The exception is colloidal suspensions of degradation products, such as the carbonaceous soot particles produced in a diesel engine or a microdieseling process. Colloidal suspension refers to the dispersion of fine particles within the lubricant, where the particles are dispersed evenly but not dissolved. In this state, the particles remain suspended throughout the lubricant due to their small size (typically between 1 and 1000 nanometers) and interaction with the surrounding fluid.
• The MPC test (ASTM D 7843) measures soluble degradation products. That is, the degradation products are soluble while in the operating fluid. During the MPC test, the sample is heated to 65 °C for 24 hours to “reset” the sample. This dissolves any degradation products that may have settled out during shipping and handling. Then, the sample is stored at room temperature for 72 hours to provide a standardized time for the soluble degradation products to come out of solution. The exception is when colloidal suspensions are present from microdieseling events, which can be isolated with the 0.45mm membrane. (In this case, the color on the patch is black rather than the brown hues associated with oxidized degradation products.)
• There is no such thing as varnish in your oil. Varnish is defined as oil-derived deposits. If it is dissolved back into the oil, it is no longer varnished, as it has transitioned back to oil degradation products.

The Aniline Point

Group II basestocks are said to have less solvency than Group I basestocks. The test most often used to measure this is Aniline Point (ASTM D611), which gauges the solvency properties of lubricating oils. It refers to the minimum temperature at which a specific volume of aniline (a polar aromatic amine) will completely dissolve in a given volume of the lubricating oil to form a clear, homogenous solution under specified test conditions. A lower Aniline Point suggests that the lubricating oil has a higher aromatic content and, hence, a higher solvency capacity. Conversely, a higher Aniline Point denotes lower aromatic content and solvency.

Here are some average aniline points for various base stocks:

Naphthenic 58 °C

Group I 100 °C

Group II 116 °C

Group III 125 °C

Group IV 127 °C

Alkylated Naphthalene 42 °C

Polyalkylated Glycol -20 °C

However, understanding the solubility of oil degradation products is more involved than simply understanding the oil’s ability to dissolve a polar constituent. It depends upon the chemistry of the degradation products and the characteristics of the oil. Polarity is just one of the parameters. A more complete understanding of the solubility of oil degradation products can be determined by studying the Hanson Solubility Parameters.

What are Hansen Solubility Parameters?

Hansen Solubility Parameters (HSP) provide:

• A numerical representation of the molecular interactions in solutions.
• Enabling a more robust understanding of solubility.
• Miscibility.
• Dispersion phenomena.

They are three values derived from a particular material’s dispersion forces, polar forces, and hydrogen bonding interactions. The three parameters are often represented as a three-dimensional coordinate (D, P, H), each depicting different forces as outlined below:

• Dispersion Forces (dd):

This parameter represents the interactions due to van der Waals forces among molecules. It quantifies the non-polar interactions in a substance, often related to the London dispersion forces resulting from instantaneous dipole moments within molecules.

• Polar Forces (dp):

This parameter accounts for the dipolar interactions within and among molecules. It quantifies the polar interactions in a substance that arise due to permanent and induced dipoles.

• Hydrogen Bonding Forces (dh):

This parameter represents the potential for hydrogen bonding within a material. It quantifies the interactions arising from hydrogen bonding, a specific dipole-dipole interaction between hydrogen atoms and electronegative atoms like oxygen or nitrogen.

One can predict whether the solute would dissolve in the solvent by analyzing the Hansen Solubility Parameters of a solute and a solvent. Materials with similar HSP values are likely to be miscible or soluble with one another. This set of parameters can be applied to predict when oil degradation products may no longer be dissolved in oils, or when varnish can be redissolved back into the oil.

Moreover, HSP values can be graphically represented in a spherical three-dimensional Hansen Space to visualize the solubility and miscibility relationships among various materials. This is a powerful tool to develop solubility enhancers to manage oil degradation products.

If the chemistry of the degradation products, as defined by D, P, and H, creates an area inside that defined by the lubricant, the degradation products will dissolve. If it is outside the area, it will not dissolve.

Figure 1: Hansen sphere made up of the three axes which can be used to understand the solubility of oil degradation products

Oil degradation products are soluble. This means that they can easily transition in and out of solution based on the equilibrium between the solute (varnish) and the solvent (oil) as seen in the varnish lifecycle in Figure 2.

The solubility of oil degradation by-products is significantly influenced by temperature. Analogous to the enhanced solubility of sugar in hot water as opposed to cold water, a rise in temperature increases the solubility of varnish in lubricating oil.

Technically, this is due to the elevated kinetic energy of molecules at higher temperatures, which facilitates the overcoming of intermolecular forces that otherwise impede solubility, thereby enabling the dissolution of more varnish.

Conversely, as the temperature diminishes, the kinetic energy of the molecules decreases, lessening the oil’s capacity to maintain the varnish in a dissolved state. This thermodynamically driven reduction in solubility during cooling promotes the precipitation of varnish from the solution, leading to its deposition on the internal surfaces of the equipment.

This phenomenon underscores the crucial role of temperature management in mitigating varnish-related complications in lubrication systems.

The Sandpaper Effect

Varnish can be complex structures of oxidation products and insoluble contaminants, such as wear metals and dirt. (In the strictest sense, even wear metals and dirt can dissolve in the lubricant under the right conditions, like water dissolving rocks as a river flows over them.)

Dr. A. Sasaki described this phenomenon as the Sandpaper Effect. The sticky nature of the oxidatively-derived varnish may allow suspended particles to stick to it, becoming trapped in the varnish. This type of varnish layer forms asperities on the surface.

Thus, when other surfaces encounter this type of varnish, they are susceptible to wear. This leads to the sandpaper effect, which ultimately damages the internals of the equipment, especially close tolerance components such as valves.

What Is the Role of Solubility Enhancers?

Solubility Enhancers can be a powerful technology to manage oil degradation products. They may be used to prevent oil degradation products from coming out of solution to form deposits or to dissolve varnish and keep it back in solution.

For a Solubility Enhancer to be deemed an effective solution, it should meet the following conditions:

1. Miscible in lubricant – this will allow it to be added to an in-service lubricant during machine operation without specialized blending equipment.
2. Wide range of compatibility – this extends to both in-service oils and system materials such as seals and paints
3. No impact on an in-service oil’s characteristics – it should not interfere with the oil’s ability to interact with contaminants such as air and water. This can severely impact the oil’s air release, foam, and demulsibility characteristics.
4. No impact on surface-active additive ingredients – this could potentially interfere with an oil’s corrosion inhibitors, antiwear, extreme pressure, or friction modifier additive systems.
5. Engineered to solubilize oil degradation products effectively – this can give them the ability to hold a large amount of degradation products without the concern of these precipitating out under oxidative stress.
6. Ability to work effectively without a varnish mitigation technology installed. This enhancer should ideally stand on its own.
7. Ashless technology should be formulated without additive metals to ensure that it doesn’t contribute to varnish formation even under the most extreme oxidative conditions and without antioxidants.

Ideally, a solubility enhancer should add value to a system by removing varnish or keeping oil degradation products in solution without compromising the integrity of the lubricant or system.

Solvancer® – the Solubility Enhancer of the Future

Solvancer (a patent-pending technology) was developed using a blend of specialized synthetic API Group V chemistries. This technology has outstanding solubility characteristics and is compatible with many base oils and fully formulated lubricants.

It doesn’t impact system materials such as seals, filters, or paint and has excellent oxidation stability and long-term deposit control characteristics. Solvancer does not cause any adverse impact on fluid properties, nor does it use surface-active chemistry.

Solvancer was used in these two applications below, and the MPC results are definitive.

For this first example, 5% of Solvancer was added to a PAO Compressor oil, and the MPC value was lowered from 48 (patch on the left) to 6 (patch on the right).

In this second example, Solvancer was added to a Group II-based Air compressor lubricant, and the MPC value was lowered from a rating of 67 to 11.

Not All Oil Soluble Cleaners are Created Equally.

There are now multiple oil-soluble cleaners available in the market. These chemistries may effectively dissolve varnish immediately before an outage to prevent system decontamination or oil flushing between oil exchanges. However, some chemistries may have unintended consequences if left in the system for too long.

To estimate the long-term performance of different solubility enhancers, they were mixed with new oil and subjected to the oxidative stresses in the Turbine Oil Performance Prediction (TOPP) test. This test procedure stresses the oil according to ASTM D7873 for 12 weeks.

Although many physical and chemical tests are done throughout this experiment, simply looking at the patch and condition of the glassware after the experiment tells a powerful story. The comparison of DECON versus two other commercially available solubility enhancers can be seen below in Figure 6.

In this case, a new, untreated turbine oil sample produced heavy glassware deposits and an MPC of 61 after the test. The same turbine oil was treated with 3% of COMP I, COMP 2, and DECON. The DECON-treated fluid maintained deposit-free, pristine glassware and a low MPC value, as seen above.

It should be noted that COMP 2 produced even more deposits than the untreated sample. Performance tests such as this must be carried out before using oil-soluble cleaners beyond a short period, immediately before an outage.

Available Technologies

Solvancer was formulated by utilizing Hansen’s Solubility Parameters to ensure the technology is optimized for long- and short-term deposit control. The technology allows deposits to remain in solution, even when the oil cools. It is incorporated into the following Fluitec products to provide deposit control:

• DECON, DECON AO, DECON AW
• Infinity Turbine Oil

Ideally, one must first understand their solubility when determining methods for managing oil degradation products. As outlined in this article, the answer does not lie in one simple test but rather in further exploration of the actual characteristics of the varnish and the system in which it is being produced. Solubility enhancers can be optimized for deposit control where they do not compromise the other characteristics of the oil.