Sour Gas Compression
Sour gas compressor lubricants are selected for compressors handling gas streams that contain hydrogen sulfide (H₂S), frequently together with carbon dioxide (CO₂), moisture and hydrocarbons.
Sour gas adds toxicity, corrosion, containment and material-compatibility requirements beyond those of sweet natural gas. Severity follows H₂S concentration and partial pressure, moisture, CO₂ content, hydrocarbon composition, compressor design and operating conditions.
NEXT Lubricants supplies mineral, polyalphaolefin (PAO), polyalkylene glycol (PAG) and polyethylene glycol (PEG) lubricants for sour gas gathering, gas processing, acid-gas compression, reinjection and sulfur-recovery duty. Product selection accounts for both the sour-service severity and any hydrocarbon dilution that reduces the lubricant’s operating viscosity.
Sour gas is natural gas containing hydrogen sulfide, usually with carbon dioxide and water. It occurs as untreated gas containing hydrocarbons and acid gases, or as separated acid gas consisting primarily of hydrogen sulfide and carbon dioxide.
Untreated sour gas still contains propane, butane, and heavier hydrocarbons. These dissolve into the lubricant far more readily than methane and reduce its operating viscosity, so the lubricant must resist both dilution and corrosion.
Water makes sour gas corrosive. Without free water, hydrogen sulfide is primarily a toxicity and materials concern rather than a corrosive attack on lubricated surfaces.
Compression increases sour-gas severity. Partial pressure rises with total pressure, so the same gas is more severe at compressor discharge than at suction.
Carbon dioxide creates a separate corrosion mechanism when water is present. A stream containing very little hydrogen sulfide can therefore still be highly corrosive.
Corrosion protection comes primarily from the additive system, while dilution resistance comes primarily from the base fluid. Untreated sour gas and separated acid gas can therefore require different lubricant chemistries despite both being classified as sour.
How Sour Gas compression works and the compressor's role
Sour gas occurs in oil-and-gas reservoirs and process streams that contain measurable concentrations of H₂S. Before the gas enters a sales pipeline or downstream process, it undergoes compression, dehydration, sweetening and removal of H₂S, CO₂ and other contaminants.
Compressors raise the gas pressure for gathering, processing, treatment, reinjection or movement between process stages. Reciprocating and rotary screw compressors serve sour duty according to gas composition, pressure ratio, flow rate and facility design.
The lubricant protects bearings, cylinders, piston rings, packing, rotors and other moving components. Its exposure to the sour gas follows the compressor design and lubrication point. In reciprocating compressors, the frame lubricant remains isolated from the process gas while the cylinder and packing lubricant contacts it directly. In oil-injected rotary screw compressors, gas–lubricant contact is extensive.
Because H₂S is both toxic and corrosive, sour-gas compressors require specialized metallurgy, packing arrangements, distance pieces, purge systems and controlled venting. The compressor manufacturer and the applicable sour-service standards establish these equipment requirements.
Sour Gas Gathering & Boosting
Field and gathering compressors handle raw natural gas containing H₂S, CO₂, water and hydrocarbons before the gas reaches central treatment facilities.
Gas Processing & Sweetening
Compressors around gas-treatment facilities handle sour feed gas before H₂S and CO₂ removal, along with process streams associated with the sweetening system.
Acid Gas Injection
Acid gas separated during natural-gas sweetening carries concentrated mixtures of H₂S and CO₂. These streams are compressed to high pressure and reinjected underground, which makes acid-gas injection one of the more demanding sour-gas compression applications.
Sour gas reinjection
Sour gas is recompressed and reinjected into a reservoir for disposal, pressure maintenance or hydrocarbon recovery, according to the field-development strategy.
Sulfur Recovery
Sulfur-recovery facilities handle H₂S-rich acid gas removed from sour natural gas and convert hydrogen sulfide into elemental sulfur. Compression and blower duties on these streams require materials and lubricant selection matched to the actual gas composition.
Factors Affecting Lubricant Selection
Sour gas compressor lubrication accounts for the corrosive gas components, moisture, hydrocarbon dilution and compressor operating envelope. The following factors determine the required formulation and viscosity.
- H₂S concentration and partial pressure Establish the severity of the sour service and the corresponding compressor, material and lubricant requirements.
- Moisture and free water Increase corrosion risk in H₂S- and CO₂-containing gas and affect lubricant stability, separation and component protection.
- CO₂ and complete acid-gas composition Influence corrosion severity, phase behavior and lubricant requirements, particularly in concentrated acid-gas streams.
- Hydrocarbon composition and dilution Determine whether propane, butane and heavier components dissolve into the lubricant and reduce its operating viscosity.
- Suction and discharge conditions Set H₂S and CO₂ partial pressure, compressor loading, discharge temperature, gas density and lubricant exposure.
- Lubricant and gas temperature Govern lubricant viscosity, oxidation, gas solubility, condensation and the phase behavior of the complete gas stream.
What NEXT needs to recommend a lubricant
A lubricant recommendation is based on the information below. Provide whatever information is available; NEXT will identify whether any additional details are required.
- Compressor Details Manufacturer, model, serial number and compressor type, such as reciprocating, rotary screw or centrifugal.
- Current Lubricant and Performance Current oil, oil volume, operating hours and any problems with viscosity, deposits, consumption, carryover or lubricant life.
- Gas Composition Main hydrocarbon components and any water, CO₂, H₂S, nitrogen, oxygen or other substances present. An existing gas-composition report can also be provided.
- Operating Conditions Suction and discharge pressures and temperatures, oil temperature and relevant operating limits for each compression stage.
- Application and Specific Requirements How the compressor is used and any purity, catalyst, material-compatibility, minimum-viscosity or other application-specific requirements.
- Final Recommendation NEXT evaluates the available information and confirms the recommended product, lubricant chemistry and ISO viscosity grade, with compatibility and changeover guidance where required.
Operational Benefits of Correct Lubricant Selection
Selecting the lubricant according to the sour-gas composition, compressor and operating conditions can provide several operational benefits.
- Reduced Unplanned Downtime Prevents lubrication-related wear, overheating, valve problems, deposits and unexpected compressor shutdowns.
- Corrosion Protection in Wet Sour Service Protects lubricated surfaces against corrosive attack from H₂S and CO₂ in the presence of moisture.
- Extended Component Life Protects cylinders, piston rings, packing, bearings, rotors and other lubricated components.
- Stable Operating Viscosity Maintains sufficient film strength after hydrocarbons dissolve into and dilute the lubricant.
- Longer and More Predictable Service Intervals Resists oxidation, viscosity loss and contamination for controlled maintenance planning.
- Clean Running and Deposit Control Minimizes varnish, carbon and deposit formation for cleaner valves, cylinders and lubricant-system components.
Recommended NEXT Sour Gas Compressor Lubricants
NEXT GPL PAG
Sour Gas / Light–Medium Hydrocarbon Compression
Base Oil: PAG
ISO Range: 32 – 680
NEXT GPL PAG-WS
Sour Gas / Medium – Heavy Hydrocarbon Compression
Base Oil: PAG-WS
ISO Range: 32 – 460
Our technical team can help identify the right product.
Lubricant Selection, Technical Support and Compatibility Documentation
NEXT combines application knowledge, laboratory data and an extensive internal cross-reference database to support lubricant selection, conversions and compressor troubleshooting.
Depending on the application, we can provide:
- Application-Specific Product Recommendations Lubricant recommendations based on gas or refrigerant composition, compressor design, operating conditions and current performance issues.
- Lubricant Cross-Referencing Identifies suitable NEXT alternatives by comparing base-oil chemistry, viscosity, application, specifications and operating requirements.
- Compatibility and Conversion Documentation Provides chemistry comparisons, mixture-test data, material compatibility, flushing requirements and top-off or changeover guidance.
- Dilution Data and PVT Graphs Shows how gas or refrigerant concentration, pressure and temperature affect lubricant dilution, density and operating viscosity.
- Troubleshooting and Root-Cause Support Supports investigations into foaming, oil carryover, dilution, deposits, corrosion, high lubricant consumption and reduced oil life.
What type of oil is used in sour gas compressors?
Any of the five chemistries, because this page covers two genuinely different stream types.
Most sour duties still carry hydrocarbons. Gathering and boosting, processing and sweetening, and sour gas reinjection all handle produced gas with propane and heavier components still in it. Both requirements are live at once: the C3+ content decides the base stock, while water and acid gas decide how hard the additive package works and how long it lasts.
Acid gas injection and sulfur recovery are the exception. The hydrocarbons have been stripped out upstream, so the dilution axis largely collapses and the selection becomes almost entirely a corrosion and additive-stability question.
Hydrocarbon content therefore sets the base stock — mineral or PAO for lean streams, PAG for light to medium hydrocarbons, water-soluble PAG or PEG where dilution is severe — and sour severity sets what the additive package has to survive.
Why does sour gas dilute the compressor oil?
Because untreated sour gas is still mostly hydrocarbons. Hydrogen sulfide and carbon dioxide are the components that get the attention, but on a gathering, processing or reinjection duty they are a minority of the stream — the bulk of it is methane with propane, butane and heavier components alongside.
Those heavier components dissolve into the lubricant far more readily than methane does, and dissolved gas reduces operating viscosity. Solubility also rises with pressure, so the discharge end of the machine dilutes hardest.
The important point is that this has nothing to do with how sour the gas is. A very sour stream can be lean and barely dilute the oil at all, while a mildly sour stream can be rich enough to need the most dilution-resistant chemistry in the range. The two conditions are assessed separately and then answered by one lubricant.
Separated acid gas is the exception — the hydrocarbons have been stripped out, so dilution largely stops being a factor.
What H₂S concentration makes a gas compressor a sour-gas application?
None on its own. Sour service is defined by partial pressure in the presence of water, not by concentration.
Partial pressure is total absolute pressure multiplied by the hydrogen sulfide mole fraction, so compression raises it in exact proportion. The same gas at 0.1 mol % is ten times more severe at 5,000 psia than at 500 psia, with no change in composition. A machine can therefore take suction on gas that is marginally sour and discharge gas that is unambiguously sour.
Convert to partial pressure at the highest stage the stream reaches, and read it alongside the water content rather than on its own. Reading parts per million and stopping there understates the duty.
Does moisture make sour gas compression more severe?
Water is the variable that decides whether the corrosion mechanisms operate at all.
The cracking and metal-loss mechanisms associated with hydrogen sulfide require an aqueous phase. Without free water, and without tensile stress, sour gas is a toxicity and materials consideration rather than an active corrosion problem at the lubricated surfaces.
Two things put water into a stream that a gas analysis may not show. Raw sour gas is water-saturated at reservoir conditions, and water-holding capacity falls as gas cools — so interstage coolers on a multi-stage sour machine produce free water reliably rather than occasionally. And acid gas holds more water at saturation than sweet gas does, so the acid components increase the water load rather than reducing it.
Can the same lubricant be used for mildly sour gas and acid gas injection?
Not automatically. Mild sour gas and concentrated acid-gas streams can differ enormously in H₂S, CO₂, pressure and moisture. Acid gas injection commonly compresses separated H₂S/CO₂ mixtures to high pressure for underground injection, so lubricant and compressor requirements should be evaluated for that specific duty.
Does CO₂ change sour-gas lubricant selection?
Yes, and it should be assessed as its own mechanism rather than as a footnote to hydrogen sulfide.
Carbon dioxide dissolves in the water phase to form carbonic acid, which lowers pH and drives general wall thinning plus localized pitting. That is a different attack from the sulfide mechanism, with a different scale forming on the metal and a different set of drivers — partial pressure, temperature, water cut and flow velocity.
The practical consequence: a stream with little or no measurable hydrogen sulfide can still be corrosive if carbon dioxide and water are present at pressure. Specifying an uninhibited lubricant because the gas is “sweet” ignores it.
Carbon dioxide also dissolves into the lubricant and contributes to dilution, so a stream carrying significant CO₂ dilutes more than its hydrocarbon content alone suggests.
When should PAG or PEG be used instead of PAO in sour gas?
When hydrocarbon content requires it — which is a separate question from how sour the gas is.
Corrosion protection comes from the additive system and is present across the range. Dilution resistance comes from the base stock. Because those are independent, “more sour” is not a reason to move up the chemistry ladder, and “richer” is not a reason to worry more about corrosion.
A very sour, very lean stream needs excellent corrosion protection and almost no dilution resistance. A mildly sour, very rich stream needs the opposite. Both are common, and confusing them is how a machine ends up with a lubricant that solves the wrong problem.
Is acid gas injection the most demanding sour-gas application?
On corrosion, generally yes. On dilution, it is the mildest — which surprises people.
An acid gas injection stream is largely hydrogen sulfide and carbon dioxide, water-saturated off the regenerator, and compressed through several stages to very high injection pressure. Partial pressures at the final stage are enormous, and interstage cooling condenses water repeatedly.
But there is little in that stream to dilute the lubricant. Amine solvents absorb acid gas and pick up very little hydrocarbon, so the regenerator overhead is dominated by hydrogen sulfide and carbon dioxide. Dilution resistance therefore buys a property the machine largely cannot use, and a mineral or PAO base stock with a proven inhibitor package is usually the correct answer. Confirm the actual stream analysis rather than assuming: aromatic co-absorption is a known amine unit issue, and physical solvent processes carry considerably more hydrocarbon than chemical amines do.
Cylinder lubrication at those pressures is normally once-through, so consumption rate and feed rate control matter more than drain interval.
Explore Other Gas Compression Applications
CO₂ Compression
Lubricants for carbon dioxide compression in process, industrial, transport and injection applications.
Carbon Capture & CCUS
Natural Gas Gathering
Biogas
Lubricants for methane/CO₂ gas streams where H₂S, moisture and other contaminants influence compressor lubrication.