NGL Plant Compression: Matching Lubricant to Position, from Inlet to Fractionation
A natural gas processing plant operates several compressors on streams that vary significantly. Feed gas is rich and mixed, residue gas is primarily methane, and fractionation overheads are nearly pure single components. Mechanical refrigeration compressors run a closed refrigerant loop—typically propane—for refrigeration, not process gas. This article focuses on oil-flooded screws and lubricated reciprocating cylinders where the lubricant contacts the gas. Oil-free and dry-sealed machines, including turboexpanders, are beyond its scope. The correct approach is position-by-position: identify what each machine actually encounters, then ascend the chemistry ladder—hydrotreated mineral, polyalphaolefin (PAO), polyalkylene glycol (PAG), water-soluble polyalkylene glycol (PAG-WS), and polyethylene glycol (PEG)—as the concentration of propane and heavier hydrocarbons (C3+) increases.
Gas plant compression isn't a single duty. The natural gas liquids (NGL) recovery route and fractionation train dictate which compressors exist, and their streams range from 90% methane to nearly pure propane. A single lubricant across the plant would either over-specify most machines or under-specify the most demanding ones.
Dilution is driven by the partial pressure of the dissolving component, along with oil temperature and lubricant chemistry—not by total pressure. A fractionation overhead at 20 bar (290 psi) of nearly pure propane presents a far higher propane driving force than rich feed gas at 25 bar (363 psi) containing 8% propane.
Mechanical refrigeration is common in many gas plants, including cryogenic ones where it provides supplemental pre-cooling, and it is often specified as if it were a process gas compressor. It is a hydrocarbon refrigeration duty.
CO₂ changes the calculation. It dissolves readily into PAG, so a fuel or feed stream carrying 10 to 15% CO₂ produces more total dilution than its hydrocarbon content alone suggests. A complete gas analysis is a crucial selection input, not a formality.
Mechanical refrigeration compressors have conflicting requirements: resist dilution by the refrigerant, yet still return oil from the chiller.
PAG-family and hydrocarbon-based lubricants are incompatible. Plant-wide consolidation to two or three products, grouped by duty, is realistic, but it follows chemistry-family lines. Crossing families requires a full drain and flush.
Why a gas plant is not one application
Gas arriving at a processing plant has been conditioned. Free water, acid gases, and solids are largely removed at or before the inlet, so the corrosion and free-water problems prevalent in gathering recede. What replaces them is variety within a single facility.
Three variables change from machine to machine:
- Gas composition. Feed gas may contain 8 to 15 % C3+. Residue gas is approximately 90 % methane. A depropanizer overhead is essentially pure propane. A mechanical refrigeration loop typically runs on pure refrigerant—in gas plants, usually propane.
- Lubricant-gas contact. Oil-flooded screw compressors and lubricated reciprocating cylinders bring oil into direct contact with the process stream—these machines are the subject of this article. Oil-free and dry-sealed machines lubricate only bearings and are a separate consideration.
- Machine temperature. A mechanical refrigeration suction operates far below ambient; a fractionation reboiler-side machine may exceed 100 °C (212 °F). The same lubricant cannot be optimal for both.
Selection, therefore, must be made per compressor. The remainder of this article examines the positions in the order the gas encounters them.
The plant in brief
The process operates in four stages.
- Conditioning. Incoming feed gas is compressed to processing pressure, dehydrated, and stripped of acid gases such as carbon dioxide (CO₂) and hydrogen sulfide (H₂S).
- Recovery. The gas is chilled, causing heavier hydrocarbons to condense and separate as a liquid. This liquid forms the NGL stream. Chilling is achieved by mechanical refrigeration, Joule-Thomson expansion across a valve, or a turboexpander, depending on the required recovery depth.
- Fractionation. The recovered NGL liquid is separated into individual products in a series of distillation columns. Each column removes the next-lightest component overhead and passes the remainder down the train.
- Residue and product handling. The methane-rich gas remaining is compressed for pipeline or export. The separated liquids are stored, loaded, and shipped.
Compression can occur at every stage—the extent is a design choice. Columns operate with reboiler heat and and condensers, and dedicated compression is present only where the design calls for it: vapor recompression, refrigerated overhead condensing, or product vapor handling. Some trains handle several such duties; a conventional train with steam reboilers may have almost none.
The fractionation train
| Column | What Enters | Leaves Overhead | Bottoms Passed On | Compression at This Point |
|---|---|---|---|---|
| Demethanizer | Chilled feed from the chiller or expansion step | Methane-rich residue gas | C2+ NGL, to the deethanizer | Residue gas compression |
| Deethanizer | C2+ NGL | Ethane | C3+ NGL, to the depropanizer | Overhead condensing commonly runs on the mechanical refrigeration loop—itself a compressor duty; some designs add overhead recompression |
| Depropanizer | C3+ NGL | Propane | C4+ NGL, to the debutanizer | Overhead vapor handling, and propane routed to refrigerated storage |
| Debutanizer | C4+ NGL | Mixed normal butane and isobutane | C5+ natural gasoline | Overhead vapor handling and product transfer |
| Butane splitter | Mixed butanes | Isobutane | Normal butane | Product handling and loading vapor recovery |
Reading down the “leaves overhead” column reveals a governing pattern: each successive column produces a heavier and purer hydrocarbon. A compressor at the demethanizer handles methane; one at the depropanizer handles nearly pure propane. These are not variations of a single duty.
Feed gas and inlet compression
Feed gas compressors raise incoming gas to processing pressure. If feed arrives from a high-pressure line already at pressure, this position doesn’t exist. Where it does, the stream is rich, treated but not fractionated, and typically contains the full C1 through C6+ range, plus nitrogen and often CO₂.
Dilution here is moderate. C3+ content is usually in the high single digits to low teens by mole, and total pressure is significant. Therefore, a mineral or PAO lubricant may be diluted below the original equipment manufacturer (OEM) viscosity requirement, while a PAG typically maintains its grade. The qualifier matters: PAG resists hydrocarbon dilution, but CO₂ readily dissolves into it. Thus, on a CO₂-bearing stream, the PAG advantage narrows, and the calculation must include both contributions.
Two features distinguish this duty from natural gas gathering. Liquid slugging is less likely because inlet separation is engineered, not field-improvised. Also, CO₂ can be significant; it readily dissolves into PAG, increasing total dilution beyond what hydrocarbon content alone predicts.
The failure mode is unremarkable and gradual—viscosity below requirement, bearing wear, shortened life. Routine fluid analysis detects it long before the machine does; without a sampling program, the machine reports it first.
The NGL recovery route determines the plant
How a plant recovers liquids determines which compressors exist and what they handle. There are four routes, each presenting different lubrication challenges.
| Route | Cooling Method | Typical C3 Recovery | Compression Duties Created |
|---|---|---|---|
| Mechanical refrigeration | Propane chiller, vapor-compression cycle | 88–92% | Refrigeration compressor plus feed and residue compression |
| Joule–Thomson | Isenthalpic expansion across a valve | 80–88% | Recompression after a large pressure drop |
| Turboexpander | Isentropic expansion through a turbine | Over 90%, with C2 recovery over 70% | Residue compression; often supplemental mechanical refrigeration ahead of the cold box |
| Lean oil absorption | Contacting with lean oil | 85–94% | Recompression plus lean oil circulation |
The JT route trades efficiency for simplicity. Expansion across a valve is isenthalpic—no work is extracted, unlike a turbine—so for a given pressure drop, it produces less cooling. The pressure drop involved is substantial, commonly 34 to 69 bar (500 to 1,000 psi). Whatever pressure is dropped must generally be recompressed, creating a recompression duty on rich gas.
The turboexpander route achieves the deep recovery temperatures required. Recovering over 90% of propane and over 70% of ethane typically requires temperatures in the range of −87 to −101 °C (−125 to −150 °F), and cryogenic plants routinely operate below −101 °C (−150 °F).
Mechanical refrigeration
Mechanical refrigeration, also called external refrigeration, is a closed-loop vapor-compression cycle, usually on propane, driven by a reciprocating, screw, or centrifugal compressor. It chills the feed gas so that heavier hydrocarbons condense and drop out in a cold separator.
It appears in gas plants in two distinct roles:
- As the primary recovery method. Straight refrigeration plants are widely used for hydrocarbon dew point control and moderate NGL recovery. Evaporating temperature typically ranges from −29 to −40 °C (−20 to −40 °F), achieving C3 recoveries of 88 to 92%. Published plant designs show mechanical refrigeration systems operating at around −23 °C (−10 °F) and 1.15 barg (16.7 psig) for dew point duty.
- As supplemental pre-cooling in a cryogenic plant. Where feed gas is rich, a mechanical refrigeration system is commonly integrated into a turboexpander design to provide supplemental cooling ahead of the cold box. One documented turboexpander design operates its propane low stage at −37 °C (−35 °F) and 0.23 barg (3.4 psig); another chills feed gas to −35 °C (−31 °F) with propane before the gas reaches the expander.
That second role is the commercially important one. A plant described as cryogenic commonly still contains a mechanical refrigeration package, often specified with the same process gas compressors because it is treated as part of the same plant rather than as a separate refrigeration machine.
A mechanical refrigeration compressor works a closed circuit of essentially pure propane. This is a hydrocarbon refrigeration duty, and the lubricant must satisfy two conflicting requirements.
Propane is highly soluble in mineral oil and PAO, which are non-polar like the refrigerant itself. Although suction pressure in these systems is low—often only a fraction of a bar (a few psi) above atmospheric—the oil in a flooded screw’s separator sits at discharge pressure in an atmosphere of pure propane, and any sump equalizes toward system pressure at standstill. Partial pressure at the oil is therefore far higher than the suction gauge suggests, leading to severe dilution. A lubricant selected on suction pressure alone will be badly underspecified.
No oil separator is perfect. The small fraction that escapes—commonly around 10 ppm in the refrigerant stream—travels to the condenser, through the expansion device, and into the chiller. Propane boils off there; the lubricant does not, because its boiling point is far above chiller temperature. Without an effective return path, oil concentrates in the chiller with two consequences: heat transfer progressively degrades, and the compressor eventually runs short of oil.
The heat transfer penalty is not marginal. An increase of 0.1 mm in oil film thickness measurably affects cooling capacity, which in a gas plant shows up as lost NGL recovery rather than as a lubrication complaint. The plant sees reduced propane recovery or has to chill harder for the same result, and the cause sits at the bottom of the chiller.
These two requirements point in opposite directions. The chemistry that resists dissolving propane is also the chemistry propane does not want to mix with. Therefore, maximum dilution resistance tends to come with minimum miscibility—and oil that does not travel with the refrigerant does not return from the chiller on its own. High miscibility solves the return problem but brings heavy dilution with it. The two properties are not the same thing, but in hydrocarbon refrigerant service, they move together.
- NEXT GPL PAG is formulated at that balance point for propane service. Its data sheet explicitly claims both properties: exceptional resistance to viscosity dilution by hydrocarbon gases and reliable miscibility with hydrocarbon refrigerants for proper oil return. It is specified for propane (R-290), butane (R-600), and isobutane (R-600a) refrigeration and for industrial heat pumps on hydrocarbon refrigerants.
- NEXT GPL PAG-EO fits systems built around separation rather than circulation — the separation paragraph, restructured so the product leads and the system description follows.
- NEXT GPL PAG-WS takes over at the severe end of the duty. A measured NEXT comparison on a near-pure propane stream — four chemistries at the same grade and condition, published in the gas dilution article — shows the selection moving up the ladder as condensing pressure and oil temperature rise: at high condensing pressure with hot oil, NEXT GPL PAG falls short of the requirement and NEXT GPL PAG-WS becomes the answer. The calculation, not the chemistry name, makes the call per machine.
A separate detail worth knowing: mechanical refrigeration units commonly use monoethylene glycol (MEG) injection for hydrate prevention on the process side. That is a process-side chemical, not a lubricant concern, but glycol carryover into the compressor is a contamination pathway worth checking when fluid analysis shows unexplained water.
Detailed lubricant selection for propane and other hydrocarbon refrigerants—miscibility windows, evaporating temperature limits, and grade selection—is covered in the hydrocarbon refrigeration material linked at the end. What matters at the plant level is recognizing that this machine is not a process gas compressor and should not be specified as one.
Fractionation
The fractionation train separates the recovered NGL stream through up to five towers in series: demethanizer, deethanizer, depropanizer, debutanizer, and butane splitter. Ethane leaves the deethanizer overhead, propane the depropanizer overhead, mixed normal and isobutane the debutanizer overhead, and C5+ natural gasoline as bottoms.
Each overhead is heavier and purer than the last. Not every train compresses at every column—many condense overheads against refrigeration and move liquids by pump—but where compression does occur, it makes these positions the most demanding compression territory on site.
Gas dissolves into a lubricant in proportion to its partial pressure—the total absolute pressure multiplied by the mole fraction of the component. Oil temperature and chemistry determine how much dissolves at that driving force. Partial pressure is what changes from position to position. Compare two duties on the same plant:
| Duty | Total Pressure | Propane Mole Fraction | Propane Partial Pressure |
|---|---|---|---|
| Rich feed or fuel gas | 25 bar (363 psi) | 0.084 | ≈2.1 bar (30 psi) |
| Depropanizer overhead | 20 bar (290 psi) | ≈1.0 | ≈20 bar (290 psi) |
The overhead machine runs at a lower total pressure but roughly ten times the propane driving force. Depropanizer columns commonly operate at 17 to 24 barg (250 to 350 psig), so this is a normal operating condition rather than an extreme case. An operator reading the pressure gauge has no obvious reason to expect a harder duty on the lower-pressure machine.
The progression reflects increasing dilution severity, not increasing quality:
| C3+ Severity | Typical Stream | Chemistry | Why It Sits Here |
|---|---|---|---|
| Very low | Residue gas, approximately 90% methane | Mineral or PAO | Dilution is not the constraint; oxidation life and cost are |
| Low to moderate | Feed gas, 5–10% C3+ | Mineral, PAO, or PAG | Mineral or PAO may suffice; PAG buys margin as composition drifts |
| Moderate | Feed gas with 10–15% C3+, fuel gas with CO2, and deethanizer overhead | PAG or PAG-WS | Water-insoluble PO PAG holds grade where PAO will not; PAG-WS adds margin on the richer streams |
| High | Rich recompression, depropanizer overhead, and debutanizer overhead | PAG, PAG-WS, or PAG-EO | The EO/PO copolymer resists heavier components; PAG reaches some of these duties at a heavier grade |
| Severe | Product loading, C5+ vapor | PAG-WS or PEG (PAG-EO) | Very low hydrocarbon solubility governs; PAG-WS serves where the calculation confirms it |
Moving up the ladder is not an upgrade in the ordinary sense. Each step trades miscibility and cost for dilution resistance, and a step taken further than the duty requires provides a property the machine cannot use—while introducing a chemistry that may be incompatible with the hydrocarbon-based lubricants running elsewhere on site.
Product handling, loading and vapor recovery
Once fractionated, propane and butane are stored and loaded. Vapor handling on these systems means compressing an essentially pure heavy hydrocarbon at low pressure, which is the same problem as a fractionation overhead and often worse, because the vapor may carry C5+ from tank breathing.
This is NEXT GPL PAG-EO (PEG) territory. Where a lubricant needs to hold viscosity in an atmosphere of near-pure butane or pentane, very low hydrocarbon solubility is the property that makes it possible. Detailed treatment of low-pressure heavy hydrocarbon vapor duty belongs with vapor recovery, linked below
Residue and sales gas compression
After recovery and treatment, methane-rich residue gas is compressed for pipeline, storage or export. Sales gas is typically around 90 % methane with the balance mostly ethane.
Dilution here is low. What governs instead is oxidation life, deposit control and long service intervals, because these machines run continuously between turnarounds and are often the largest on site. A mineral or PAO grade is normally correct.
A worked calculation
The following is a NEXT pressure-volume-temperature (PVT) calculation output for a high-pressure fuel gas compressor running NEXT GPL PAG-WS-220 with the oil at 70 °C (158 °F). The gas stream is rich, dry, and CO₂-bearing, typical of plant fuel gas and recompression duties.
Gas Composition
| Component | Mol % | Component | Mol % |
|---|---|---|---|
| Methane | 61.356 | Isopentane | 1.075 |
| Ethane | 8.543 | n-Pentane | 0.937 |
| Propane | 8.416 | Hexanes | 0.471 |
| Isobutane | 2.849 | Nitrogen | 0.523 |
| n-Butane | 3.035 | Carbon dioxide | 12.795 |
| Total | 100.000 |
| Condition | Temperature | Absolute Pressure |
|---|---|---|
| Discharge | 110 °C (230 °F) | 25 bar (363 psi) |
| Oil conditions (lubricating point) | 70 °C (158 °F) | — |
Both operating viscosities are evaluated at the 70 °C (158 °F) oil temperature, each with its corresponding calculated dissolved gas.
Three points emerge from this:
- A fresh ISO viscosity grade (ISO VG) 220 lubricant delivers 16.7 cSt at discharge. Based on the data sheet alone, 220 cSt of protection would be assumed.
- This comparison isolates the gas. Both viscosities are at the same 70 °C (158 °F) oil temperature, so the drop from 62.2 to 16.7 cSt between suction and discharge conditions is due to dissolved gas, not heat. An additional 2.2 points of dissolved gas at discharge pressure remove roughly three-quarters of the viscosity—a phenomenon no viscosity-temperature chart illustrates.
- CO₂ at 12.8% contributes to this result. Carbon dioxide readily dissolves into PAG, making this a mixed-gas dilution figure. Omitting CO₂ from a gas analysis would understate the true impact.
Calculations are extrapolated from measured solubility data on NEXT products and apply specifically to them.
The NEXT NGL compressor lubricant range
Figures from current technical data sheets, Rev. 09/2025.
| Product | Base Stock | ISO VG | VI | Pour Point | Flash Point | Where It Belongs in a Gas Plant |
|---|---|---|---|---|---|---|
| NEXT GPL MIN (222 Series) | Hydrotreated mineral | 32–680 | 97–110 | −45 to −10 °C (−49 to 14 °F) |
220–267 °C (428–513 °F) |
Residue and sales gas, gas turbines. DIN 51515-1 TD/TG, ISO 8068 |
| NEXT GPL PAO (215 Series) | PAO with ester | 15–220 | 120–159 | −63 to −49 °C (−81 to −56 °F) |
213–260 °C (415–500 °F) |
Residue gas, lighter feed gas, and cold-ambient sites |
| NEXT GPL PAG (141 Series) | Water-insoluble PAG (PO) | 32–680 | 178–238 | −57 to −30 °C (−71 to −22 °F) |
208–230 °C (406–446 °F) |
Feed gas, fuel gas, deethanizer overhead, and mechanical refrigeration |
| NEXT GPL PAG-WS (162 Series) | Water-soluble PAG (EO/PO) | 32–680 | 180–268 | −54 to −27 °C (−65 to −17 °F) |
217–246 °C (423–475 °F) |
Depropanizer and debutanizer overhead, rich recompression, and high-pressure duty |
| NEXT GPL PAG-EO (224 Series) | PEG | 22–150 | 100–175 | −54 to −30 °C (−65 to −22 °F) |
179–270 °C (354–518 °F) |
Product loading, C5+ vapor, and severe-dilution service. Very low hydrocarbon solubility |
Which lubricant does a mechanical refrigeration (propane) compressor in a gas plant need?
A hydrocarbon refrigeration lubricant, not a process gas lubricant. The duty involves a closed propane loop, and the lubricant must resist dilution by propane while still returning from the chiller. NEXT GPL PAG is formulated for that balance and is specified for R-290 service. For the most demanding conditions—high condensing pressure, hot oil—calculations guide the selection to a higher grade. Where oil management relies on separation rather than circulation, NEXT GPL PAG-EO, with its very low hydrocarbon solubility, becomes a viable option.
Do cryogenic plants have mechanical refrigeration?
Usually, yes. When feed gas is rich, a mechanical refrigeration system is commonly integrated into a turboexpander design to provide supplemental pre-cooling ahead of the cold box. Documented designs run propane low stages at around −37 °C (−35 °F). When present, this package is a refrigeration compressor and should be specified as such.
Why does a depropanizer overhead compressor need a different lubricant from the inlet compressor?
Because dilution is proportional to the partial pressure of the dissolving component. Feed gas at 25 bar (363 psi) with 8% propane presents approximately 2 bar (30 psi) of propane driving force. A depropanizer overhead at 20 bar (290 psi) of near-pure propane presents approximately 20 bar (290 psi). The overhead machine operates at a lower total pressure and a far higher dilution driving force.
Can one lubricant cover an entire gas plant?
No. A residue gas machine, a mechanical refrigeration compressor, and a depropanizer overhead screw are three different applications. Grouping two or three products by duty is typically achievable, and consolidation should follow chemistry-family lines because PAG and hydrocarbon-based lubricants require a full flush for changeover.
Does NGL-rich gas always mean a higher ISO viscosity grade?
No. A higher fresh grade is one way to compensate for dilution; a more dilution-resistant chemistry is often the better route because it maintains viscosity rather than starting higher and falling further. The correct approach depends on the calculated in-service viscosity versus the OEM requirement.
What does CO₂ in plant fuel gas do to selection?
It increases dilution. CO₂ dissolves readily into PAG, so a stream carrying 10 to 15% CO₂ produces more total dilution than its hydrocarbon content alone suggests. In the worked example above, a stream with 12.8% CO₂ reached 5.43 wt% dilution at discharge and reduced a fresh ISO 220 to 16.7 cSt.