Severe VRU Compressor Oil Dilution: Causes and Solutions
Vapor recovery unit (VRU) compressors handle the vapor from crude oil and condensate storage tanks. This vapor is rich in propane and heavier hydrocarbons (C3+), components that readily dissolve into compressor oil, leading to severe oil dilution.
The cause is often misunderstood. Dilution depends on gas composition, oil temperature, oil separator pressure, and the lubricant’s chemistry. In an oil-flooded compressor, the oil separator is the critical point for evaluation, as the oil is at full discharge pressure in direct contact with compressed vapor.
A separate issue arises when water or heavy hydrocarbons cool below their dew point and mix with the oil as a liquid. This condensed liquid can contaminate the oil and strip away the lubricating film.
A vapor recovery unit compresses the richest gas on site: vapor flashing off stored crude or condensate. It takes that gas from atmospheric to line pressure, often in a single stage, making it one of the most demanding duties for a compressor lubricant in the gas service industry.
Tank vapor contains far more propane, butane, pentane, and heavier components than pipeline-quality natural gas. This heavy hydrocarbon composition causes severe VRU dilution; pressure and temperature then determine how much ends up in the oil.
Gas solubility increases with pressure and decreases with temperature. Both factors must be considered to determine lubricant dilution.
Lubricant chemistry heavily influences dilution. In a crude tank vapor case (37 mol% C3+), three polyglycol chemistries met the compressor's viscosity requirement, with grades from ISO VG 100 to 220. In a condensate tank vapor case (53 mol% C3+), only polyethylene glycol chemistry met the requirement at a practical viscosity grade; alternatives required grades too high for an outdoor skid.
Dew points must be checked at discharge pressure—lubricants have no effect on the temperature at which water or heavy ends condense.
A heavier ISO grade is not a substitute for the right chemistry. A higher viscosity grade oil of the same chemistry dissolves the same proportion of gas by weight. An ISO VG 100 polyethylene glycol outperforms an ISO VG 680 of a chemistry that dissolves four times more gas.
Vapor recovery in brief
A vapor recovery unit (VRU) is a compressor package that captures hydrocarbon vapor from storage tanks and sends it into a pipeline, a fuel gas system, or the suction of a larger compressor, instead of letting it vent to the atmosphere. VRUs are located wherever produced liquid is stored: well sites, terminals, and loading facilities.
- Where the vapor comes from. Crude oil or condensate leaves upstream separation equipment at a pressure well above tank pressure. The U.S. EPA cites a typical separator pressure of around 2.4 barg (35 psig), though actual pressures vary by facility. When that liquid enters a tank sitting near atmospheric pressure, the light components flash out of solution as vapor. Two smaller sources add to it: working losses, as the liquid level rises and pushes vapor out of the headspace, and breathing losses, as the tank warms and cools over the day.
- Why it is recovered. Vented tank vapor is both a regulated emission and a salable product. EPA technical guidance reports VRU recovery efficiencies of about 95%, which is also the reduction level several U.S. control requirements specify.
- How a VRU works A suction scrubber removes free liquid and returns it to the tank. The compressor then raises the vapor from near-atmospheric pressure to whatever the destination needs: a gathering line, a meter run, a larger compressor, or the site fuel gas system. A control system keeps the machine from pulling a vacuum on the tank.
- What makes the duty hard The compressor takes suction at just tens of millibar to roughly 0.15 bar (a few ounces to 2 psi) above atmospheric — essentially atmospheric pressure — and discharges at anywhere from a few bar to tens of bar (tens to hundreds of psi). Single-stage compression ratios of 5 to 15 are common. The gas it handles is usually the richest hydrocarbon stream on site. And although tank-headspace vapor starts out in equilibrium with the stored liquid, it can change on the way to the compressor: heat transfer, pressure loss, air ingress, residence time in piping, knockout equipment, and upstream drainage all alter it.
Vapor Sources and Characteristics
| Source | Vapor Stream Characteristics | Compressor Type | Gas–Oil Contact |
|---|---|---|---|
| Crude oil stock tank | Flash, working and breathing vapor; C3+-rich, warm | Flooded screw or rotary vane | Direct |
| Condensate / light oil tank | Very rich, high C4–C6 content | Flooded screw or rotary vane | Direct |
| Vapor recovery tower (VRT) | Stabilization flash vapor ahead of the tank | Flooded screw | Direct |
| Produced water tank | Wet, lean-to-moderate hydrocarbon, water-saturated | Screw or rotary vane | Direct |
| Truck and rail loading racks | Displaced saturated vapor, intermittent, ambient-driven | Screw or reciprocating | Direct |
| Pig traps and LACT vents | Intermittent slugs, liquid carryover likely | Screw or reciprocating | Direct |
| Dehydrator still vent and flash tank | Wet, glycol-bearing, moderate hydrocarbon | Small screw | Direct |
| Flowback tanks | Highly variable, sand and liquid carryover | Screw or rotary vane | Direct |
Two things stand out. Every source in this table puts the gas in direct contact with the oil — the compressor types that dominate vapor recovery offer no dry-sealed escape route. And severity is set by the stream, not the suction gauge: a produced water tank and a condensate tank at the same suction pressure present completely different lubricant problems.
What Tank Vapor Contains
Flash vapor is always richer in volatile components than the liquid it came from. EPA guidance notes that lighter crude oils, roughly above 36° API, tend to produce more vapor. But API gravity alone does not predict oil dilution. What matters is the vapor composition and the operating conditions, and those are the inputs any dilution calculation needs.
Heating value gives a quick sense of how rich the stream is. Typical pipeline natural gas runs around 35.4–41.0 MJ/Sm³ (950–1,100 Btu/scf); recovered tank vapor has been reported above 74.5 MJ/Sm³ (2,000 Btu/scf). A high Btu number tells you the gas is rich; it does not tell you how much C3+ is in it or how much will dissolve in the oil.
The practical rule: if the site has a gas analysis, use it. If all that exists is a Btu number from the sales meter, and that number is anywhere near tank-vapor territory, the lubricant is on severe duty and should be selected accordingly.
Why Low Suction Pressure Is Not the Cause of Dilution
Ask why VRU oil thins out, and the a common answer is “low suction pressure.” It sounds plausible. It is also backwards.
Gas dissolves into a lubricant in proportion to how much of that gas is pressing on it — its partial pressure. Partial pressure is simply each component’s share of the total pressure. Solubility rises with pressure and at the same time falls with temperature. On the suction side of a VRU, at a few ounces to 2 psi above atmospheric, every component’s partial pressure is close to its atmospheric value. That makes the suction side the least diluting point in the entire machine.
Dilution happens at the other end. In a flooded screw compressor, the oil separator — the sump — operates at full discharge pressure, and the oil in it is in intimate contact with fully compressed vapor. Partial pressures there are at their maximum. That is where the dilution calculation belongs.
Low suction pressure does matter, just indirectly, in three ways:
Starting near atmospheric and discharging at line pressure produces single-stage ratios of 5:1 to 15:1. The ratio, together with discharge temperature, gas throughput, oil circulation rate, and separator residence time, determines how hard the oil works.
A stream available at a few ounces of pressure came off a liquid surface at atmospheric conditions. That is a diagnostic clue: expect rich, saturated vapor.
A tank running near atmospheric pressure can pull in air if the control band slips. Oxygen accelerates oil oxidation, changes the gas composition, and widens the flammable envelope — reason enough to maintain tank pressure within the control band and monitor oxygen where ingress is credible.
None of these actually dissolve gas into the oil. The dilution itself comes down to composition of the gas stream, temperature, and pressure.
When the Gas Turns to Liquid: The Dew-Point Margin
Dissolved gas is only half the problem. The other half — and the half no lubricant can fix — is whether any of the stream condenses outright.
Every gas stream has a dew point — the temperature at which liquid starts to form — and across the pressure range a VRU spans, that dew point rises with pressure. A compressor raises pressure and temperature simultaneously, so whether the discharge stays safely in the vapor region depends on which climbs faster.
A published screening criterion from compressor package engineering quantifies this: liquid contamination becomes a concern when the dew point of the gas at discharge pressure comes within 22 °C (40 °F) of the discharge temperature. That gap is called the superheat margin.
A published case study shows how quickly the margin disappears. A water-saturated stream enters at 41 °C (105 °F) and 0.5 barg (7 psig) and is compressed to 10.3 barg (150 psig), discharging at 91 °C (195 °F). The dew point at discharge sits only 7 °C (13 °F) below the discharge temperature — far inside the 22 °C threshold — and water condenses on the separator walls and ends up in the oil.
The same guidance identifies three conditions that raise the risk:
| Screening Flag | Threshold | Why It Matters |
|---|---|---|
| Gas is hot | Inlet above 32 °C (90 °F) | A warm, saturated stream carries several times more water than a cool one—water-holding capacity climbs steeply with temperature. |
| Gas is heavy | Specific gravity above 0.90, high C3+ | The hydrocarbon dew point at discharge rises with molecular weight. |
Now apply those two flags to a VRU:
- Elevated Temperature. Tank vapor comes off a liquid surface in an outdoor vessel, and breathing losses peak with solar heating. Tank vapor above 32 °C (90 °F) in summer is routine, not exceptional.
- High Specific Gravity. A stream at 55.9–74.5 MJ/Sm³ (1,500–2,000 Btu/scf) has a specific gravity well above 0.90. Rich tank vapor meets this flag as a matter of course; the leaner sources in the table above — produced water tanks, some vent recovery — are the exceptions, which is one more reason the stream, and not the label ‘VRU’, sets the duty.
Dissolved Gas vs. Condensed Liquid
These two mechanisms behave differently in the machine, appear differently in oil analysis, and require different fixes. Distinguishing between them is crucial.
Dissolved gas enters the oil in proportion to its partial pressure. Its concentration can be calculated from the gas composition and operating conditions. The dissolved gas decreases the oil viscosity evenly. The solution lies with the lubricant: choose a chemistry that dissolves less hydrocarbon, or start with a higher viscosity grade grade, or both.
Condensed liquid is a different issue. Liquid hydrocarbons arriving in the separator or sump displace oil from surfaces and strip the lubricating film. Filtration does not help — a coalescing filter separates droplets from gas, not condensate from oil once they are mixed in the sump.
Condensate ingress is also intermittent, making it easy to miss. It appears at night when ambient temperature drops, during start-up before the machine is warm, and after a slug from an upstream vessel. An oil sample pulled at the wrong moment can appear perfectly normal.
The fixes for condensation are process-side, not lubricant-side:
Properly size the suction scrubber to remove free liquid before the compressor inlet. For gas expected to arrive wet, a dedicated VRU scrubber vessel is standard practice to collect natural gas liquids that would otherwise condense upstream of the inlet.
Maintain a discharge temperature high enough to preserve the superheat margin.
If the gas must be cooled, condense it deliberately in a purpose-built vessel, not accidentally in the oil system.
The lubricant cannot solve a condensation problem. What it can do is minimize dissolved gas and better maintain its viscosity if some condensate does get through.
The Chemistry Ladder for Vapor Recovery Units
On the lubricant chemistry side, a lubricant’s ability to dissolve hydrocarbons depends on its polarity. Mineral oil, polyalphaolefin (PAO), and hydrocarbon gas are all non-polar, and non-polar substances mix freely, leading to significant dilution. Polyalkylene glycol (PAG) is polar: roughly one in three atoms along its backbone is oxygen, and this polarity makes hydrocarbons far less soluble in it.
For vapor recovery, the chemistry ladder extends to its top step:
| Step | Chemistry | Where It Fits in Vapor Recovery |
|---|---|---|
| Conditional |
NEXT GPL MIN (222 Series) NEXT GPL PAO (215 Series) |
Dilute severely in C3+-rich vapor. Acceptable only on lean seal-vent or fuel-gas recovery duties. |
| Entry |
NEXT GPL PAG (141 Series) |
Water-insoluble propylene oxide PAG. Lean vapor, seal and packing vent recovery. |
| Working grade |
NEXT GPL PAG-WS (162 Series) |
Ethylene oxide/propylene oxide (EO/PO) copolymer designed for crude tank vapor, produced water tanks, pig traps, and still vents. |
| Severe duty |
NEXT GPL PAG-EO (224 Series) |
Polyethylene glycol (PEG). Ideal for condensate tank vapor, loading racks, and applications operating near the dew point. Not suitable for gas streams with very high water content. |
The ladder ranks severity of duty, not product quality. Each step trades miscibility and cost for dilution resistance, so choosing a grade above the duty pays for properties the machine never uses.
PEG earns the top step because it dissolves only a fraction of the hydrocarbon that non-polar chemistries absorb—roughly a quarter, in the worked cases below. At that level, dissolved gas essentially stops being the cause of oil degradation. That is worth more than it sounds: it leaves condensation as the main failure pathway, so an operator can treat it purely as a process problem instead of untangling two causes at once.
Two Tank Vapor Streams, Calculated
The compositions below are illustrative tank vapor streams constructed by NEXT to represent the two ends of vapor recovery service.
| Component | Mol % | Component | Mol % |
|---|---|---|---|
| Methane | 44.000 | Heptane | 1.100 |
| Ethane | 14.500 | Nitrogen | 1.300 |
| Propane | 16.000 | Carbon dioxide | 2.800 |
| Isobutane | 4.200 | Hydrogen sulfide | 0.050 |
| n-Butane | 8.000 | Water vapor | 0.150 |
| Isopentane | 3.100 | ||
| n-Pentane | 2.600 | ||
| Hexane | 2.200 | Total | 100.000 |
| Component | Mol % | Component | Mol % |
|---|---|---|---|
| Methane | 31.000 | Heptane | 2.200 |
| Ethane | 12.000 | Nitrogen | 0.800 |
| Propane | 18.500 | Carbon dioxide | 3.000 |
| Isobutane | 6.000 | Water vapor | 0.200 |
| n-Butane | 12.000 | ||
| Isopentane | 5.500 | ||
| n-Pentane | 4.800 | ||
| Hexane | 4.000 | Total | 100.000 |
For scale, the rich gathering stream and gas plant feed stream worked in the Natural Gas Gathering Technical Article carry about 11.6 and 9 mol % C3+ respectively.
Two things follow directly from this table.
First, the oil sump pressure line is critical, as it makes the suction figure misleading. Stream B draws suction at 1.05 bar, but its oil is at 14 bar. Every partial pressure driving gas into that oil is set at 14 bar, not 1.05. In a flooded screw, the sump runs close to discharge temperature—85–90 °C (185–194 °F) here, 5–10 °C below discharge, not the oil injection temperature after the cooler.
Second, both streams require a dew-point check at discharge before any lubricant discussion is useful. Stream B—53% C3+, compressed to 14 bar (200 psi), discharging at 100 °C (212 °F)—is precisely the case where the 22 °C (40 °F) superheat margin must be calculated, not assumed. If the margin is insufficient, no lubricant choice will remedy the outcome.
Both streams were run through the NEXT PVT calculation with three lubricant chemistries. Gas composition and operating conditions remained constant in each case; only the lubricant changed, isolating the comparison to chemistry. Dilution equilibrium is calculated at discharge conditions—the pressure and temperature the oil actually experiences in the separator—and the compressor’s requirement of 20 cSt is assessed on the diluted oil at the 65 °C (149 °F) supply point, where the cooled oil enters the machine.
Before the pass/fail tables, one result independently addresses the suction-pressure question. The tool reports dissolved gas at suction and discharge conditions separately for the same oil and gas:
| Lubricant (ISO 150) | Dilution at Suction, Stream A | Dilution at Discharge, Stream A | Dilution at Suction, Stream B | Dilution at Discharge, Stream B |
|---|---|---|---|---|
| NEXT GPL PAG | 5.94 wt% | 10.53 wt% | 8.70 wt% | 22.54 wt% |
| NEXT GPL PAG-WS | 4.85 wt% | 8.31 wt% | 6.81 wt% | 18.44 wt% |
| NEXT GPL PAG-EO | 1.23 wt% | 2.68 wt% | 1.54 wt% | 5.27 wt% |
Even at essentially atmospheric pressure, the richest stream pushes almost 9 wt% of gas into a non-polar-leaning oil—the gas composition is responsible, not the pressure. Compression then doubles the dilution on Stream A and triples it on Stream B, which is why the calculation is especially important at the discharge of the compressor.
| Lubricant | ISO Grade | Dissolved Gas | Viscosity at Discharge | Viscosity at 65 °C Supply | Verdict |
|---|---|---|---|---|---|
| NEXT GPL PAG | 150 | 10.53 wt% | 10.8 cSt | 19.5 cSt | Falls just short |
| NEXT GPL PAG-WS | 150 | 8.31 wt% | 15.3 cSt | 29.1 cSt | Passes |
| NEXT GPL PAG-EO | 150 | 2.68 wt% | 17.6 cSt | 38.7 cSt | Passes |
Same grade, same gas, and the delivered viscosity spans a factor of two — 19.5 to 38.7 cSt — purely on chemistry. Now the more practical question: what is the lightest grade each chemistry can serve this stream with?
| Lubricant | Minimum Passing ISO Grade | Dissolved Gas | Viscosity at 65 °C Supply |
|---|---|---|---|
| NEXT GPL PAG | 220 | 10.58 wt% | 24.2 cSt |
| NEXT GPL PAG-WS | 100 | 8.46 wt% | 20.9 cSt |
| NEXT GPL PAG-EO | 100 | 2.54 wt% | 27.3 cSt |
The polyethylene glycol was also run one grade lighter: ISO VG 68 delivers 19.6 cSt, just under the 20 cSt requirement. That places the boundary precisely for this stream — on this crude tank vapor composition, PEG needs ISO VG 100 and nothing more. A richer or warmer stream moves the boundary, which is what the calculation is for.
So for crude tank vapor, the selection is a genuine choice, but not an equal one. The water-insoluble PAG needs two grade steps more to do the same job, while PAG-WS and PEG both serve from ISO VG 100 — PEG with a third of the dissolved gas and 6 cSt more headroom. On an outdoor, unmanned skid that margin buys easier cold starts, better separator return, and room for the days the gas runs richer than the analysis said.
Note in the table that stepping from the water-insoluble PAG from ISO VG 150 to 220 changed its dissolved gas from 10.53 to 10.58 wt%. The higher viscosity oil absorbed the same proportion of gas. Dilution is dependent on the lubricant chemistry, not on the viscosity.
| Lubricant | ISO Grade | Dissolved Gas | Viscosity at Discharge | Viscosity at 65 °C Supply | Verdict |
|---|---|---|---|---|---|
| NEXT GPL PAG | 150 | 22.54 wt% | 4.6 cSt | 7.64 cSt | Fails |
| NEXT GPL PAG-WS | 150 | 18.44 wt% | 7.1 cSt | 13.1 cSt | Fails |
| NEXT GPL PAG-EO | 150 | 5.27 wt% | 11.9 cSt | 27.8 cSt | Passes |
At a common ISO VG 150, only the polyethylene glycol meets the requirement. It absorbs 5.27 wt% of gas from this vapor; the water-insoluble PAG absorbs 22.54 wt% — over four times as much — from the same stream. An oil carrying a fifth of its weight in dissolved hydrocarbon is not the fluid its data sheet describes.
The intuitive response to a viscosity shortfall is to start with a higher viscosity grade. Stream B was re-run with each chemistry stepped up:
| Lubricant | ISO Grade | Dissolved Gas | Viscosity at 65 °C Supply | Assessment |
|---|---|---|---|---|
| NEXT GPL PAG | 680 | 22.58 wt% | 17.7 cSt | Fails at the top of its range |
| NEXT GPL PAG-WS | 460 | 18.22 wt% | 22.8 cSt | Passes—at an impractical grade |
| NEXT GPL PAG-EO | 100 | 5.04 wt% | 20.6 cSt | Passes at a lighter grade |
The water-insoluble PAG fails at ISO VG 680 — the top of its range, so there is nowhere left to go. Stepping from 150 to 680 is a 4.5× increase in fresh grade, but it delivers only 2.3× the working viscosity (7.64 to 17.7 cSt), and the requirement is still out of reach.
The water-soluble PAG technically gets there, and the honest version of this result is worth stating: at ISO VG 460, three grade steps above where it started, it clears the requirement by 2.8 cSt. But look at what that costs. An ISO VG 460 fluid on an outdoor skid rated to −15 °C (5 °F) is a real cold-start and separator-return problem, and it delivers roughly the same working viscosity a polyethylene glycol provides from ISO VG 100.
The dilution column explains all of it. Across every grade step, each chemistry dissolved essentially the same proportion of gas — 22.54 vs 22.58 wt% for the water-insoluble PAG across a 4.5× grade jump, 18.44 vs 18.22 wt% for the water-soluble PAG across 3×. The gas does not care how heavy the fresh oil is. So every grade step starts from the same dilution penalty and delivers less than the one before.
The conclusion is not that a heavier grade would work but be awkward on a cold start. On a stream like this, a heavier grade of the wrong chemistry either never reaches the required viscosity or reaches it at a grade the installation cannot live with. An ISO VG 100 polyethylene glycol at 20.6 cSt beats an ISO VG 680 of a chemistry that dissolves four times more gas.
Stream A and Stream B represent distinct gas compositions and operational parameters. Stream B exhibits a substantially higher C3+ content and operates at an elevated oil-system pressure. Both factors contribute to increased equilibrium dilution. These cases illustrate the combined effect of composition and operating conditions, rather than isolating gas composition as the sole variable.
The NEXT Vapor Recovery Unit Lubricant Range
Figures from current technical data sheets, Rev. 09/2025.
| Product | ISO VG Range | Position in Vapor Recovery |
|---|---|---|
| NEXT GPL PAG (141 Series) | 32–680 | Lean vapor, seal and packing vent recovery. |
| NEXT GPL PAG-WS (162 Series) | 32–680 | Crude tank vapor, produced water tanks, pig traps and still vents. |
| NEXT GPL PAG-EO (224 Series) | 22–150 | Condensate tank vapor, loading racks and rich-gas duties requiring maximum resistance to equilibrium dilution. |
| NEXT GPL PAO (215 Series) | 15–220 | Lean recovered streams where calculated hydrocarbon dilution remains within the required operating-viscosity limit. |
| NEXT GPL MIN (222 Series) | 32–680 | Lean vapor-recovery service where the calculated diluted viscosity remains above the compressor’s minimum requirement. |
Lubricant Analysis in Vapor Recovery Service
NEXT Lubricants provides technical support and an Oil Analysis Program for vapor recovery service. Routine analysis follows viscosity, water content, acidity, and contamination trends, and catches dilution, condensation, oxidation, and separator problems before they become downtime. One caution applies to every row below: a trend tells you the oil is changing, not why. Each finding needs checking against operating data and the fresh-oil baseline before a cause is assigned.
| Finding | Primary Interpretation | Required Confirmation |
|---|---|---|
| Viscosity falling steadily | Dissolved-gas dilution, liquid hydrocarbon contamination, or mixing with a lower-viscosity lubricant. | Compare gas composition, separator pressure, oil temperature and lubricant additions with the previous baseline. Confirm with repeat viscosity, flash point and hydrocarbon analysis. |
| Viscosity falling in steps and partially recovering | Intermittent condensate ingress, a start-up or shutdown event, a process upset, or inconsistent sampling conditions. | Review water and hydrocarbon dew-point margins, scrubber drains, cooler operation, nighttime conditions and the operating state at the time of sampling. |
| Viscosity rising | Oxidation, loss of volatile components, incompatible lubricant mixing, or suspended contamination. | Check discharge and oil temperatures, oxygen ingress, FTIR oxidation, total acid number, insolubles and lubricant identification. |
| Total acid number rising | Oxidation, acidic process contamination, lubricant mixing, or a change in additive chemistry. | Compare against the fresh-oil baseline. Check FTIR, water content, H₂S concentration, oxygen ingress and elemental analysis before assigning a cause. |
| Oil consumption rising | Oil carryover, external leakage, separator malfunction, increased volatility, or changed operating conditions. | Inspect the separator element, differential pressure, oil level, return lines and external leak points. Compare consumption with gas flow, pressure ratio and discharge temperature. |
| Water content rising | Wet-gas ingress, water condensation, a cooler leak, or contamination during maintenance or sampling. | Confirm with Karl Fischer testing, the calculated water dew point, scrubber and drain performance, cooler pressure testing and a repeat sample taken under controlled conditions. |
What type of oil is used in a vapor recovery unit compressor?
Typically, polyalkylene glycol (PAG) or polyethylene glycol (PEG) lubricants are preferred. This is because most recovered vapor is sufficiently rich in hydrocarbons that mineral and polyalphaolefin (PAO) lubricants would experience excessive viscosity loss.
This preference is due to chemical similarity. Mineral oils and PAO are non-polar, akin to the hydrocarbons in the vapor, leading to ready mixing. This dissolved gas subsequently reduces the operating viscosity. PAG, however, incorporates oxygen in its molecular backbone, rendering it polar and significantly reducing hydrocarbon solubility.
Mineral and PAO lubricants remain suitable for genuinely lean recovery applications, such as compressor seal vents and some fuel-gas recovery systems, but they are not the default choice for general vapor recovery.
Why do VRU vapors significantly reduce compressor oil viscosity?
The primary reason lies in the origin of the vapor.
Tank vapor is generated when hydrocarbon liquid flashes as it transitions from separator pressure to atmospheric storage. Consequently, it carries the heavier components (“heavy tail”) of that liquid. Heavier hydrocarbons dissolve into lubricants much more readily than lighter ones.
A useful field indicator is heating value. While pipeline-quality gas falls within a specific range, recovered tank vapor commonly exhibits a much higher heating value, which correlates directly with molecular weight. An operator with only a BTU figure from the sales meter already possesses sufficient information to be concerned about potential viscosity reduction.
Does low suction pressure cause oil dilution in a VRU?
No, this is the most persistent misconception in this application.
Gas dissolves into a lubricant in proportion to its partial pressure, and solubility increases with pressure. Therefore, the near-atmospheric suction side represents the least diluting condition within the machine. Dilution primarily occurs at the discharge and in the oil separator, where pressure is highest and the sump is at discharge pressure.
Low suction pressure is relevant for three indirect, yet real, reasons: it dictates a high compression ratio, leading to elevated discharge temperatures and a large volume of gas passing through each unit of oil; it signifies a vapor originating from a liquid surface, which is the actual diagnostic indicator; and a unit that pulls tanks into a vacuum can ingest air, accelerating oxidation.
None of these factors directly cause dilution. The mechanism of dilution is fundamentally linked to the gas stream composition, temperature, and pressure.
Is oil dilution always worse in a VRU than in other gas compressors?
Not automatically; the honest answer is that it depends on the specific stream. However, the odds of significant dilution are unusually high in VRUs.
Three conditions elevate the risk of hydrocarbon condensation in any compressor: a warm inlet, a heavy gas, and the presence of water and acid gas. Recovered tank vapor often meets all three simultaneously because it originates from an outdoor vessel warmed by the sun, is inherently heavy, and comes from a liquid containing water.
This confluence of factors makes vapor recovery a demanding duty, rather than solely the suction pressure. Nevertheless, it is still crucial to evaluate the specific stream. For example, a lean vent-recovery compressor and a condensate tank VRU are both termed vapor recovery but present different challenges.
What is the difference between dissolved gas and condensed liquid?
These represent distinct failure modes requiring different responses, hence the importance of the distinction.
Dissolved gas enters the lubricant in proportion to its partial pressure. It is calculable from composition and operating conditions, reversible with changing conditions, and thins the lubricant uniformly. Proper chemistry selection addresses this issue.
Condensed liquid does not merely lower the viscosity of the oil; it displaces it from surfaces and washes away the lubricating film. Once mixed into the sump, it cannot be filtered out. It arrives unevenly: at night when ambient temperatures drop, during start-up before the machine reaches operating temperature, and after a slug from an upstream vessel. A sample taken at an inopportune moment might appear normal.
While a more dilution-resistant lubricant better maintains viscosity when condensate is present, it does not prevent the condensate from forming.
When should PAG be used instead of PAO in a VRU?
PAGs are generally preferred for most tank vapor duties, with the primary question usually being which PAG rather than whether to use one.
PAO and mineral oils are non-polar and experience significant dilution in C3+-rich vapor, making them suitable only for genuinely lean recovery applications. Water-insoluble PAGs are appropriate for lighter vapor and vent recovery. Water-soluble PAGs are used for crude tank vapor and wetter streams. PEG is suitable for condensate tanks, loading vapor, and any stream operating near its dew point.
A critical constraint for conversion is that PAGs and hydrocarbon-based lubricants are incompatible. Therefore, switching from a mineral or PAO charge requires a full drain, flush, and filter change, rather than just a top-up.
When should NEXT GPL PAG-EO be used in a vapor recovery unit?
NEXT GPL PAG-EO should be considered when dilution must be nearly eliminated rather than merely reduced, and when a heavier viscosity grade cannot achieve the desired outcome.
Its hydrocarbon solubility, typically below 3 wt%, means the operating viscosity remains close to the neat viscosity at temperature. This simplifies grade selection, making it a straightforward viscosity-at-temperature calculation without a large dilution correction.
This is particularly important when increasing the viscosity grade to compensate for dilution has reached its practical limit. Attempting to compensate for severe dilution by moving up two or three ISO grades can result in a lubricant that is too viscous to feed at start-up and too viscous to return. At this point, the correct strategy is to prevent viscosity loss rather than to start with a higher initial viscosity.
For lean vent-recovery duties, this product offers a level of resistance that the machine may not require.
Can one lubricant be used for several VRUs on the same site?
Only after a thorough comparison of the streams. Units on the same lease can exhibit greater differences than units in entirely different industries.
A crude tank VRU, a condensate tank VRU, and a loading rack compressor face substantially different C3+ content. This difference is significant enough to necessitate a change in lubricant chemistry, not just grade.
A lubricant adequate for the condensate unit will be over-specified on the leaner units — having dilution resistance they do not need — but it works, and can avoid two incompatible chemistries on one location.