Wet and Rich Gathering Gas: How Composition and Water Influence Compressor Lubricant Selection
Gathering compressors handle raw wellhead gas containing the full hydrocarbon range, water at saturation, carbon dioxide (CO₂), and often hydrogen sulfide (H₂S). Lubricant selection depends on two variables. First is the concentration of propane and heavier hydrocarbons (C3+), as these components dissolve into the lubricant and reduce operating viscosity. Second is water, which dictates two different approaches: where free water can be separated and drained, a hydrotreated mineral oil (HTMO) or a polyalphaolefin (PAO) that sheds water is appropriate; where free water cannot be avoided, a water-soluble polyalkylene glycol (PAG-WS) that holds it in solution is the safer choice. Neither is universally correct; the deciding factor is whether water can be kept out of the lubricant.
Gathering compressors are the first machines to compress gas essentially as it arrives from the wellhead — with a full hydrocarbon range, water at saturation, and often acid gas. Therefore, lubricant selection is based on two factors: C3+ dilution and the water condition.
For an oil-flooded screw compressor, the target viscosity is 20 to 30 cSt at the oil injection temperature, measured on the diluted lubricant rather than the fresh ISO viscosity grade (ISO VG).
Mineral oils, PAO, and natural gas are all non-polar, so they mix readily, leading to high dilution. Polyalkylene glycol (PAG) is polar, making hydrocarbons correspondingly less soluble in it.
Raw gathering gas arrives water-saturated. Free water appears when the gas cools because the amount of water the stream can hold decreases with temperature.
A gas stream becomes more sour as it is compressed. H₂S partial pressure equals total absolute pressure multiplied by H₂S mole fraction. Consequently, the discharge side of a gathering compressor can cross the National Association of Corrosion Engineers (NACE) sour-service threshold even if the suction side does not. Wet H₂S is corrosive; without water, H₂S generally does not cause the cracking that defines sour service.
PAG and hydrocarbon-based lubricants are not interchangeable. Switching between these families requires a drain and flush; changing within a family is covered by compatibility testing.
What makes gathering gas different
Raw natural gas from production wells contains a full range of hydrocarbons along with carbon dioxide, hydrogen sulfide, nitrogen, water, and other impurities. Dehydration, sweetening, and liquids recovery all occur downstream. A gathering compressor is the first machine to compress the stream in essentially the condition it is delivered from the wellhead.
Three well types feed gathering systems, each presenting unique challenges. Associated gas from crude oil wells arrives with the oil and is typically rich in C3+ fractions. Non-associated gas from gas wells is leaner but more often sour. Condensate wells produce gas saturated with condensate, which is the most challenging case for a gathering lubricant.
Methane content varies widely by field, sometimes falling as low as 65 mole percent. A large United States survey of treated pipeline gas averaged 92.3% methane with 3.6% ethane, 0.8% propane, and 0.5% butane. The difference between these two figures highlights the distinction between a gathering lubricant problem and a transmission lubricant problem.
The gathering system in brief
Gas moves through a gathering system in four steps.
- At the well. Gas leaves the wellhead with produced liquids and water. A separator splits gas, hydrocarbon liquid, and water. The gas is often boosted immediately because reservoir pressure is no longer sufficient to move it. Tanks holding the separated liquid release flash and breathing vapor, which is increasingly recovered rather than vented or flared.
- Across the pad and field lines. Gas from several wells joins a common header and travels through low-pressure field lines to a booster station. The composition at that header is a blend, which changes whenever a well is added, choked back, or shut in.
- At the central gathering station. Field gas is combined, boosted again, and usually dehydrated. If the gas is sour, acid gas removal occurs here or downstream. This is where the largest machines on the system are located.
- Out to processing. Treated or partly treated gas is compressed into a trunk line and sent to a processing plant. What arrives there is the feed gas for a gas plant.
Compression occurs at every step, and the duties are not the same. Suction pressure falls toward the wellhead, richness rises toward the tanks, and water is present almost everywhere.
| Position | Gas or Fluid Stream | Compressor Type | Gas–Oil Contact |
|---|---|---|---|
| Wellhead booster | Raw wet associated gas, full C1–C7+ range, saturated | Reciprocating, gas-engine driven, or screw | Direct |
| Casing gas / wellsite vapor recovery | Very rich C3+ flash vapor, near-atmospheric suction | Screw or reciprocating | Direct |
| Tank vapor recovery | Flash and breathing vapor, C3–C6 rich, wet | Screw or reciprocating | Direct |
| Pad / multi-well booster | Blended raw gas, variable composition, saturated | Oil-flooded screw | Direct |
| Separator flash gas | Rich, saturated, low suction pressure | Screw or reciprocating | Direct |
| Central station inlet booster | Combined field gas, wet, often sour | Multi-stage reciprocating or screw | Direct |
| Central station, large frame | Combined field gas, partly treated | Centrifugal with dry gas seals | None — bearings and gears only |
| Trunk line / station discharge | Dehydrated or partly treated gas | Reciprocating or centrifugal | Direct or none |
| Dehydration flash and still vent recovery | Wet rich vapor off the glycol unit | Small screw | Direct |
| Gas lift compression | Recycle gas returned to the wells, high pressure | Reciprocating | Direct |
| Acid gas injection | H2S- and CO2-rich, water-saturated | Reciprocating | Direct |
| Engine fuel gas skid | Slipstream of field gas | Small screw or reciprocating | Direct |
The chemistry and grade for any of these positions depend on the actual pressures, temperatures, and gas mixture—which is what the calculation further below exists to establish.
Richness tends to increase as suction pressure falls, so the lowest-pressure machines on the system—tank and casing vapor recovery—face the most severe dilution. And gas–oil contact is direct almost everywhere, because centrifugal machines with dry gas seals typically appear only at the largest stations. Gathering is overwhelmingly a direct-contact lubrication problem, which is the opposite of what a reader arriving from a gas plant might assume.
Dilution: why polarity decides how much dissolves
Heavier hydrocarbons dissolve into the lubricant more readily than lighter ones. Methane causes limited viscosity loss, propane and butane cause moderate loss, and pentane and heavier cause substantial loss. Solubility rises with pressure and falls with temperature.
Base stock chemistry governs how much dissolves, and the mechanism is polarity. Mineral base stocks, PAO, and natural gas are all non-polar, so they mix naturally, and the dilution rate is high. PAG is polar—in a typical PAG molecule, roughly every third backbone atom is oxygen—so hydrocarbons are less soluble in it. Published comparisons put methane solubility in PAG at roughly half that in PAO or mineral oil, with PAO and mineral behaving similarly to one another.
That is the whole argument for moving up the PAG ladder as C3+ content rises, and in a rich stream, it is a strong argument. Where mineral or PAO would be diluted below the viscosity the bearings need, PAG typically holds grade. One caveat travels with it: CO₂ dissolves readily into PAG, and gathering gas usually carries some, so on a CO₂-bearing stream, the calculation has to include both contributions.
Liquid hydrocarbons are a separate and more severe case than dissolved gas. Liquids need to be knocked out at the compressor intake or kept in the vapor phase by a sufficiently high discharge temperature. If they reach the lubricant, a mineral or PAO charge dilutes heavily, and the resulting viscosity can fall below what a bearing film needs. PAG handles this better, with one caveat worth knowing: phase separation between the hydrocarbon liquid and the PAG can occur in the separator vessel. That is acceptable provided no pure hydrocarbon liquid reaches the bearings.
Water: two defensible strategies, one deciding question
This is where gathering diverges from most gas duties and where the industry genuinely disagrees.
Raw gathering gas is saturated with water at reservoir conditions. This quantity is calculable — the McKetta and Wehe correlation, reproduced in the GPSA Engineering Data Book, gives the saturated water content of a hydrocarbon gas as a function of temperature and pressure in pounds of water per million standard cubic feet. Sweet gas at 66 °C (150 °F) and 207 bar (3,000 psia) holds roughly 104 lb/MMscf (about 1,670 mg/Sm³) before corrections for gas gravity and formation water salinity.
That number is a maximum: any water beyond it condenses as free liquid. Since water-holding capacity falls as gas cools, every interstage cooler and aftercooler in a gathering station is a place where free water appears. Acid gas makes this worse rather than better: H₂S and CO₂ hold more water at saturation than methane, and corrections are required above roughly 5 % of either at pressures over 48 bar (700 psia).
So free water is not an occasional upset in gathering service. It is a design condition. Two strategies address it and both are defensible.
Mineral and PAO base stocks separate water cleanly, so it drops out in the separator and is drained. A dry sump is better for bearing life, and this is easier to achieve with non-polar base stocks. Maintaining a sufficiently high discharge temperature to keep water in the vapor phase supports the same objective. NEXT GPL PAO is specified with water content below 50 ppm and high water separation; NEXT GPL MIN is specified for water separation in wet gas service.
A water-soluble PAG has more affinity for water and holds more of it in solution under the same conditions. Technical guidance states that a water-soluble PAG can hold more than 2 % dissolved water where a mineral or PAO would form free water, and argues that keeping water dissolved minimizes corrosion compared with conditions where free water is present.
Both positions are correct about different systems, and the deciding question is not which chemistry is better. It is this:
Can the water be kept out of the lubricant, or not?
Where the station can knock liquids out at the intake, hold discharge temperature high enough to keep water in the vapor phase, and drain the separator reliably, the dry-oil strategy wins and a non-polar base stock is correct. Where water reaches the lubricant regardless — poor separation, cold ambient operation, unmanned sites with infrequent draining, heavy water cut — free water will otherwise sit at the metal surface, and a water-soluble PAG that holds it in solution is the better outcome.
This is the question the article exists to make explicit, because selecting on dilution alone produces the wrong answer whenever water, not dilution, is the governing problem — and in gathering that is common, not exceptional.
H₂S and CO₂: how compression makes the gas more sour
Wet H₂S is corrosive. Without water, hydrogen sulfide typically does not cause the cracking mechanism that defines sour service. CO₂ with water forms carbonic acid through a separate reaction. In both scenarios, water is the enabling variable, which is why water and corrosion strategies are intrinsically linked in gathering operations.
One consequence, specific to compressors, is rarely discussed. NACE MR0175 / ISO 15156 defines sour service by an H₂S partial pressure threshold of 0.05 psia in the gas phase. Partial pressure is calculated as total absolute pressure multiplied by the H₂S mole fraction. Compression increases total pressure. A stream at 34 bar (500 psia) containing 0.1 mol% H₂S has a partial pressure of 0.034 bar (0.5 psia); recompressed to 345 bar (5,000 psia), the same gas reaches 0.34 bar (5 psia).
While the gas composition doesn’t change across the machine, its severity does. A gathering compressor can take suction on marginal gas and discharge gas that is unambiguously sour, and the lubricant is exposed to the discharge conditions. Reading H₂S in ppm alone, without converting to partial pressure at discharge, underestimates the duty.
Corrosion protection in lubricants is an additive property, not a base stock property. Every NEXT GPL grade includes rust and corrosion inhibitors, passes the ASTM D665 rust test with distilled water across the full ISO range, and rates 1a on copper strip for hydrocarbon-based grades and 1b for the PAG family. These are entry requirements; the differentiator is the longevity of the additive system—an oxidation question addressed below.
Calculating in-service viscosity rather than assuming it
Field experience indicates that the optimum viscosity for most oil-flooded screw compressors is 20 to 30 cSt at the oil injection temperature. This figure applies to the lubricant as it exists in the machine, with dissolved gas. Reciprocating machines have their own OEM requirements, which govern.
The calculation proceeds as follows: Gas composition in mol %, suction and discharge conditions, and oil injection temperature yield a dilution percentage; dilution produces an in-service viscosity; the in-service target then determines which fresh ISO grade to charge. In hydrocarbon service under pressure, the difference between the fresh grade and the in-service value commonly spans one to two ISO grades.
NEXT performs this calculation for specific applications using a completed Process and Mixed Gas Lubricant Recommendation Form. The form collects the necessary data for the calculation:
Compressor manufacturer, model, type, and current lubricant
Full gas composition in mol % or vol %, covering C1 through C7, nitrogen, oxygen, CO₂, CO, hydrogen, inert gases, water vapor, ammonia, H₂S, and other constituents
Suction and discharge temperature and pressure, per stage
Oil injection temperature, oil sump temperature, and sump pressure
Maximum and minimum ambient temperature
Minimum required viscosity and maximum viscosity limit
Water vapor is a selection input, not an afterthought; the per-stage structure exists because a three-stage machine may require a different answer than a single stage suggests.
The output includes a dilution percentage and calculated viscosity at both suction and discharge conditions, along with a viscosity-temperature curve comparing the pure and diluted lubricants. Calculations are extrapolated from measured solubility data and apply specifically to NEXT products.
The two conditions can appear very different: a lubricant comfortably above target at suction can fall close to the minimum at discharge, where pressure is highest and gas is most dissolved. Discharge normally governs, and the calculation reports both conditions to highlight exceptions.
One gathering stream, worked end to end
The following is a representative gathering composition evaluated by NEXT — lean, arriving at or near water saturation at suction, carrying acid gas, and running on an oil-flooded screw.
A lean, wet, sour field gas
| Component | Mol % | Component | Mol % |
|---|---|---|---|
| Methane | 88.000 | Hexane | 0.060 |
| Ethane | 4.200 | Nitrogen | 1.300 |
| Propane | 1.800 | Carbon dioxide | 2.400 |
| Isobutane | 0.350 | Hydrogen sulfide | 0.120 |
| n-Butane | 0.450 | Water vapor | 1.100 |
| Isopentane | 0.100 | ||
| n-Pentane | 0.120 | Total | 100.000 |
Operating Conditions
C3+ content is 2.88 mol % — lean by any gathering standard, for a machine that appears identical to one handling a much richer stream.
This is not primarily a dilution problem. At under 3 mol % C3+ and a modest discharge pressure, most chemistries will maintain viscosity. The stream actually presents a water and corrosion problem: it arrives at or near saturation, will drop free water at every cooling step, and carries 1,200 ppm H₂S. Specifying it for dilution resistance addresses a problem it does not have.
The H₂S figure warrants a second look. At 0.120 mol %, the stream reaches 0.020 bar (0.29 psi) of H₂S partial pressure at its 17 bar (247 psi) discharge — several times the 0.05 psia (0.0034 bar) NACE threshold — and it carries water. While not considered “sour” in casual conversation at the wellhead, it is sour at the compressor discharge.
Measured: lean, wet gas flips the ladder
NEXT ran the stream through the range at the sump condition — oil at 65 °C (149 °F) under 17 bar (247 psi) absolute — against the 20 to 30 cSt band. Four chemistries at the same ISO VG 150 isolate the chemistry; a fifth run addresses the questions they raise.
| Lubricant | ISO VG | Dissolved Gas | Operating Viscosity | Against the 20–30 cSt Band |
|---|---|---|---|---|
| NEXT GPL PAO | 150 | 2.69 wt% | 35.8 cSt | Above the band |
| NEXT GPL PAG | 150 | 7.05 wt% | 18 cSt | Below the minimum |
| NEXT GPL PAG-WS | 150 | 14.17 wt% | 7.6 cSt | Well below |
| NEXT GPL PAG-EO | 150 | 22.25 wt% | 3.61 cSt | Well below |
| NEXT GPL PAO | 100 | 2.69 wt% | 25.6 cSt | In band |
- The chemistry ladder is inverted. In hydrocarbon-severe duty, PEG dissolves the least and PAO the most. Here, the order is reversed: the most dilution-resistant chemistry delivers the lowest viscosity, and the least resistant delivers the highest.
- The combination of lean and wet conditions is the reason. Neither condition alone inverts the ladder. The stream is too lean for hydrocarbon dilution to matter—at 2.88 mol % C3+, there isn’t enough heavy hydrocarbon to thin any of the four, removing the primary driver for which the ladder was designed. The abundant solute, besides methane, is water vapor, which is polar. Thus, the “like-dissolves-like” principle is reversed: the polarity that rejects propane attracts water. Water-soluble chemistries absorb the most water, while non-polar PAO sheds it. The dissolved fraction in the NEXT GPL PAG-EO run is predominantly the stream’s water, not hydrocarbon, as confirmed by the counter-run below. In such a lean stream, the 1.1 mol % of water vapor—often overlooked in gas analyses and selections—determines the ranking.
- The consequence is two-fold. No ISO VG 150 falls within the band: the non-polar chemistry overshoots at 35.8 cSt, and all polar chemistries undershoot. The in-band solution is NEXT GPL PAO-100 at 25.6 cSt—the lightest chemistry on the ladder, one grade down, with water managed by separation and draining as described by the dry-oil strategy.
- Removing the water proves this. NEXT re-ran the same stream with water vapor removed. The removed 1.1 mol % was redistributed as additional propane (2.900 instead of 1.800 mol %) and pentane isomers at their natural ratio, making the dry counterpart slightly richer in hydrocarbon. All four chemistries ran at ISO VG 100.
| Chemistry | Dissolved Gas — Wet Stream | Dissolved Gas — Dry Counterpart |
|---|---|---|
| NEXT GPL PAO | 2.69 wt% | 2.90 wt% |
| NEXT GPL PAG | 7.05 wt% | 2.30 wt% |
| NEXT GPL PAG-WS | 14.17 wt% | 1.69 wt% |
| NEXT GPL PAG-EO | 22.25 wt% | 0.46 wt% |
Dissolved-gas percentage is a chemistry property, not a grade property—the PAO reads 2.69 wt% at both ISO 100 and ISO 150—so the wet ISO 150 figures compare directly against the dry runs at ISO 100.
With the water gone, the ladder rights itself: non-polar chemistry accounts for the most uptake, and PEG the least, despite the dry stream carrying more propane. PEG’s uptake collapses from 22.25 to 0.46 wt% with the CO₂ still present — the vanished points were water. Lean conditions alone change nothing; dried, this stream produces the ordinary ordering. And NEXT GPL PAO-100 lands in band on both runs: 25.6 cSt wet, 24.9 cSt dry.
A richer stream flips the ladder back: past roughly ten percent C3+, hydrocarbons retake the dominant-solute role while the water stays in the stream. Neither leanness nor water flips the ladder by itself — and on a rich, wet stream, where the two axes genuinely compete, the answer moves with the conditions. That is the case to calculate, through the form below.
The runs use the composition and conditions exactly as published above. Calculations are extrapolated from measured solubility data on NEXT products and apply specifically to NEXT products.
The NEXT Gas Gathering compressor lubricant range
Figures are from current technical data sheets, Rev. 09/2025.
| Product | Base Stock | ISO VG | VI | Pour Point | Flash Point | Position in Gathering |
|---|---|---|---|---|---|---|
| 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) |
Lean, wet gas below 100 °C (212 °F) operating temperature; water separation |
| NEXT GPL PAO (215 Series) | PAO | 15–220 | 120–159 | −63 to −49 °C (−81 to −56 °F) |
213–260 °C (415–500 °F) |
Light to medium hydrocarbons, sour service, cold ambients; water content below 50 ppm |
| 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) |
Light to medium hydrocarbon dilution where viscosity retention governs |
| 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) |
Heavy hydrocarbon dilution, high pressure, and duty where free water cannot be avoided |
| 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) |
Severe dilution; very low hydrocarbon solubility |
Which lubricant chemistry is correct for wet gathering gas?
It depends on whether free water can be kept out of the lubricant. Where liquids are knocked out at the intake, discharge temperature keeps water in the vapor phase and the separator is drained reliably, a hydrotreated mineral or PAO is correct because both shed water. Where free water reaches the lubricant regardless, a water-soluble PAG holding water in solution is preferable to free water sitting at the metal surface. C3+ content then decides how far up the chemistry ladder the answer sits.
Does higher dilution resistance always mean a better lubricant for gathering?
No. The most dilution-resistant chemistry is right for a rich stream and unnecessary for a lean one, and water behavior is a separate axis from dilution behavior. A lean, wet, sour field is a water and corrosion problem, not a dilution problem, and specifying for dilution there solves nothing.
What viscosity should a gathering screw compressor see?
Field experience puts the optimum at 20 to 30 cSt at the oil injection temperature for most oil-flooded screw compressors, measured on the diluted lubricant. The fresh ISO grade is selected so that expected dilution lands on that figure, which in hydrocarbon service commonly means charging one to two grades above the target. The compressor OEM requirement governs where one is specified.
Why does viscosity keep falling on a compressor that has not changed?
The gas has changed. Declining reservoir pressure, a new pad on the header or a rising water cut all alter what arrives at the station. A sustained falling viscosity trend in fluid analysis normally reports the gas becoming richer rather than the lubricant degrading, and it calls for a fresh calculation against a current gas analysis.
Does H₂S concentration alone determine whether the service is sour?
No. Sour service is defined by H₂S partial pressure in the presence of water, with a NACE MR0175 threshold of 0.05 psia (0.0034 bar) in the gas phase. Partial pressure equals total absolute pressure multiplied by H₂S mole fraction, so compression raises it: the same gas can be marginal at suction and clearly sour at discharge. Concentration in ppm has to be converted at operating pressure before it means anything.
What information does NEXT need to calculate operating viscosity?
Gas composition in mol %, including water vapor and H₂S; suction and discharge temperature and pressure per stage; oil injection and sump temperature; ambient range; compressor make, model and type; and any minimum or maximum viscosity limit the OEM specifies. The Process and Mixed Gas Lubricant Recommendation Form collects all of it.