Compressors
What Is a Compressor
A compressor is a mechanical device that increases the pressure of a gas by reducing its volume. In oil and gas operations, compressors rank among the most critical rotating equipment. They enable natural gas transport through pipelines, gas injection into reservoirs for enhanced oil recovery, refrigeration cycles in gas processing and LNG plants, and recirculation of process gases within refineries.
Unlike pumps, which handle essentially incompressible liquids, compressors work with compressible fluids whose density, temperature, and volume change significantly during the compression process. The thermodynamic behavior of gases during compression (polytropic or isentropic) governs the power requirements and discharge temperature, making compressor engineering a specialized discipline that intersects mechanical design, thermodynamics, and process engineering.
Compressors account for a substantial share of capital expenditure (CAPEX) and operating expenditure (OPEX) in gas-handling facilities. A single large centrifugal compressor train for an LNG plant can exceed 80 MW of power and cost hundreds of millions of dollars. Because of this, compressor selection, specification, and lifecycle management are central to project economics.
The fundamental parameters that define compressor duty are summarized below.
| Parameter | Description |
|---|---|
| Suction conditions | Pressure, temperature, gas composition (molecular weight, compressibility factor Z) |
| Discharge pressure | Required outlet pressure |
| Flow rate | Expressed as actual cubic meters per hour (Am3/h) or standard cubic feet per minute (SCFM) |
| Pressure ratio | Ratio of discharge to suction pressure per stage, typically 1.5 to 4.0 |
| Power consumption | Shaft power required, driven by flow, pressure ratio, gas properties, and efficiency |
Centrifugal Compressor Cross-Section
Types of Compressors
Compressors fall into two families based on their operating principle.
Dynamic (velocity-based) compressors accelerate the gas to high velocity and then decelerate it in a diffuser, converting kinetic energy to pressure. Centrifugal and axial compressors belong to this family.
Positive displacement (volume-based) compressors trap the gas in a fixed volume that is then mechanically reduced, directly raising pressure. Reciprocating and screw compressors work on this principle.
Each type has distinct performance characteristics that suit it to particular ranges of flow rate, pressure ratio, gas composition, and operating flexibility.
Centrifugal Compressors (Dynamic)
Centrifugal compressors are the workhorses of the oil and gas industry. They use one or more rotating impellers to impart velocity to the gas, which is then converted to pressure rise in stationary diffuser passages and a volute or collector.
| Parameter | Typical Range |
|---|---|
| Flow range | 500 to 300,000 Am3/h |
| Pressure ratio per stage | 1.2 to 3.5 (varies with impeller tip speed and gas molecular weight) |
| Overall pressure ratio | Up to 100:1 with multiple stages |
| Polytropic efficiency | 75% to 88%, depending on stage count and design sophistication |
| Capacity turndown | 70-100% of design flow before surge |
Configurations
A single-stage (overhung) centrifugal compressor has one impeller cantilevered on the shaft. It suits low-ratio duties such as blowers, process air, and gas boosting. The design is simple, compact, and economical.
The multi-stage inline (beam type) layout mounts multiple impellers on a single shaft between two bearings, all facing the same direction. This is the most common arrangement for pipeline and process compressors. API 617 Chapter 2 covers this type. Barrel-type casings (vertically split) handle high-pressure services; horizontally split casings serve moderate pressures.
In a back-to-back configuration, impellers are arranged in two groups facing opposite directions on the same shaft. This arrangement balances axial thrust, reduces bearing loads, and allows intercooling between sections. It shows up regularly in gas processing and refrigeration services where two process sections have different suction conditions.
The integrally geared (multi-shaft) design runs multiple pinion shafts, each carrying one or two impellers, off a common bull gear. Each pinion spins at its optimum speed. The result is very high pressure ratios in a compact package, commonly found in instrument air, plant air, and moderate-flow process duties. API 617 Chapter 3 governs this arrangement.
Surge and Stonewall
Centrifugal compressors have an inherent minimum flow limit called the surge point. Below this flow, the gas flow through the impeller reverses direction, causing violent oscillations that can destroy the machine within seconds. Every centrifugal compressor installation requires an anti-surge control system with a recycle valve that opens to maintain flow above the surge limit.
At the opposite extreme, stonewall (choke) occurs when the gas velocity reaches sonic conditions in the impeller or diffuser throat, limiting maximum flow capacity.
Dry Gas Seals
Modern centrifugal compressors use dry gas seals (DGS) rather than oil-film seals. A DGS maintains a thin film of gas (typically clean, dry process gas or nitrogen) between a rotating and stationary ring, providing near-zero leakage and a contamination-free seal. This eliminates the oil-contamination problems of wet seals and cuts maintenance significantly.
Reciprocating Compressors (Positive Displacement)
Reciprocating compressors use a piston driven by a crankshaft to compress gas within a cylinder. They are the oldest and most versatile compressor type, capable of handling very high pressure ratios and various gas compositions including wet, dirty, and corrosive gases.
| Parameter | Typical Range |
|---|---|
| Flow range | 5 to 50,000 Am3/h (lower than centrifugal) |
| Pressure ratio per stage | 2.0 to 5.0 (higher than centrifugal) |
| Maximum discharge pressure | Up to 700 bar (10,000 psi) for re-injection services |
| Adiabatic efficiency | 82% to 92% (inherently higher than centrifugal at equivalent pressure ratio) |
| Output character | Pulsating flow (requires pulsation dampeners) |
Configurations
In a single-acting cylinder, compression occurs on only one side of the piston. This simpler construction is common in trunk-type (automotive-style) compressors and smaller industrial units.
Double-acting cylinders compress gas on both sides of the piston (head end and crank end), doubling capacity for a given cylinder size. This is the standard configuration for large process and pipeline reciprocating compressors and requires a crosshead to maintain piston rod alignment.
Lubricated machines have cylinder and packing lubricated with oil. They suit non-critical gas services where minor oil contamination is acceptable. This is the most common type.
Non-lubricated (dry-running) machines use piston rings and packing made from self-lubricating materials (PTFE, carbon-filled polymers). Oxygen service, high-purity gases, food-grade applications, and some instrument air systems demand this design. Wear rates are higher and maintenance intervals shorter than for lubricated machines.
Pulsation and Vibration
The intermittent gas discharge from reciprocating compressors creates pressure pulsations that propagate through the piping. Left unmanaged, these pulsations cause fatigue failure of piping and small-bore connections, inaccurate flow measurement, and resonance in piping and vessels.
API 618 requires a pulsation and vibration study (often called a “Design Approach 3” study) for critical installations. Pulsation dampeners (bottles) are installed at suction and discharge to attenuate pressure oscillations. An analog or digital acoustic simulation is performed during engineering to size these elements correctly.
Valves
Reciprocating compressor valves are automatic (self-acting), opening and closing in response to the differential pressure across the valve plate. Valve reliability is a primary maintenance concern; valve failures account for a significant portion of unplanned downtime. Valve types include plate (ring) valves, poppet valves, and channel valves, each with trade-offs in flow capacity, durability, and resistance to liquid slugs.
Screw Compressors (Rotary Positive Displacement)
Screw compressors use two intermeshing helical rotors (male and female) to trap and compress gas as it moves axially along the rotors from the suction to the discharge port.
| Parameter | Typical Range |
|---|---|
| Flow range | 100 to 60,000 Am3/h |
| Pressure ratio per stage | Up to 5:1 (oil-flooded) or 3.5:1 (dry) |
| Discharge pressure | Up to about 45 bar |
| Efficiency | Lower than centrifugal or reciprocating at the same duty, but competitive in their niche |
| Maintenance | Relatively low; no valves, fewer wearing parts than reciprocating |
Oil-flooded (wet screw) compressors inject oil into the compression chamber to seal clearances, cool the gas, and lubricate the rotors. The result is nearly isothermal compression, which is thermodynamically efficient. An oil separation system downstream is mandatory. These machines see wide use in gas gathering, vapor recovery, and fuel gas boosting in upstream operations.
Dry screw (oil-free) compressors keep the rotors from contacting each other or the casing; timing gears maintain clearance. No oil enters the gas stream, but internal leakage across clearances lowers efficiency. These machines serve applications where gas contamination is unacceptable, or in instrument and plant air systems.
Screw compressors governed by API 619 are widely deployed in upstream oil and gas for wellhead gas compression, gas gathering, and vapor recovery units (VRU). They tolerate liquid slugs (especially the oil-flooded type), occupy a compact footprint, run with low vibration (no reciprocating masses), and install simply. They are commonly packaged as skid-mounted units for rapid field deployment.
Axial Compressors (Dynamic)
Axial compressors move gas parallel to the shaft axis through alternating rows of rotating blades (rotors) and stationary blades (stators). Each rotor-stator pair forms one stage, and axial machines commonly have 10 to 20 stages.
| Parameter | Typical Range |
|---|---|
| Flow range | 50,000 to over 1,000,000 Am3/h (the highest flow capacity of any compressor type) |
| Pressure ratio per stage | 1.1 to 1.5 (low per stage, but cumulative over many stages) |
| Overall pressure ratio | Up to about 15:1 |
| Polytropic efficiency | 85% to 92% (highest of all compressor types at design point) |
| Operating range | Narrow; steep surge line limits turndown to roughly 85-100% of design flow |
In oil and gas, axial compressors appear primarily in three services: LNG liquefaction (propane and mixed-refrigerant compressor trains, often combined axial-centrifugal with the axial stages handling the high-volume low-pressure section), FCC air blowers (main air blower for the fluid catalytic cracking unit regenerator in refineries), and nitric acid / ammonia plants (large air compressors).
Because of their narrow operating range and high sensitivity to fouling, axial compressors are typically reserved for constant-duty, large-volume applications where their superior efficiency justifies the limited flexibility.
Reciprocating Compressor Schematic
Compressor Selection Map
Compressor type selection is governed primarily by the required volumetric flow rate and pressure ratio. The diagram below shows the approximate operating regions for each compressor family.
Comparison Table
| Feature | Centrifugal | Reciprocating | Screw (Rotary) | Axial |
|---|---|---|---|---|
| Flow range | 500 - 300,000 Am3/h | 5 - 50,000 Am3/h | 100 - 60,000 Am3/h | 50,000 - 1,000,000+ Am3/h |
| Pressure ratio (overall) | Up to 100:1 | Up to 1,000:1 | Up to 25:1 | Up to 15:1 |
| Pressure ratio per stage | 1.2 - 3.5 | 2 - 5 | Up to 5 (oil-flooded) | 1.1 - 1.5 |
| Maximum discharge pressure | ~250 bar | ~700 bar | ~45 bar | ~20 bar |
| Polytropic efficiency | 75 - 88% | 82 - 92% (adiabatic) | 70 - 85% | 85 - 92% |
| Flow character | Continuous, steady | Pulsating | Continuous, slight pulsation | Continuous, steady |
| Capacity control | Speed, IGV, recycle | Speed, unloaders, clearance pockets | Speed, slide valve | Speed, stator vanes |
| Turndown range | 70 - 100% (surge limit) | 0 - 100% (stepwise) | 10 - 100% | 85 - 100% |
| Maintenance intensity | Low-moderate | High (valves, rings, packing) | Low | Low-moderate |
| Footprint | Moderate | Large (with pulsation dampeners) | Compact | Large (long casing) |
| Liquid tolerance | Very low (damage risk) | Low (hydraulic lock risk) | Moderate (oil-flooded) | Very low |
| Typical driver | Gas turbine, electric motor | Electric motor, gas engine | Electric motor, gas engine | Gas turbine, steam turbine |
| Governing API standard | API 617 | API 618 | API 619 | API 617 |
| Relative CAPEX | High | Moderate-high | Low-moderate | Very high |
Standards and Specifications
Compressor design, manufacturing, testing, and installation in the oil and gas industry are governed by a full set of standards:
| Standard | Title / Description |
|---|---|
| API 617 | Axial and Centrifugal Compressors and Expander-Compressors. The primary specification for dynamic compressors in O&G service. Covers mechanical design, materials, testing (Type 1 and Type 2 shop tests), vibration limits, and auxiliary systems. Organized by chapters: Ch. 1 (general), Ch. 2 (centrifugal beam), Ch. 3 (integrally geared), Ch. 4 (axial), Ch. 5 (expander-compressors). |
| API 618 | Reciprocating Compressors for Petroleum, Chemical, and Gas Industry Services. Defines three design approaches with increasing levels of pulsation/vibration analysis. Design Approach 3 (most rigorous) is required for most O&G applications and mandates a detailed pulsation and mechanical vibration study. |
| API 619 | Rotary-Type Positive-Displacement Compressors for Petroleum, Chemical, and Gas Industry Services. Covers oil-flooded and dry screw compressors, as well as other rotary types (sliding vane, liquid ring). |
| API 614 | Lubrication, Shaft-Sealing, and Oil-System Equipment and Auxiliaries. Specifies lube oil consoles, seal oil systems, overhead rundown tanks, and associated instrumentation for compressor trains. |
| API 670 | Machinery Protection Systems. Defines vibration monitoring (radial, axial, bearing), temperature monitoring, speed sensing, and trip logic for critical compressors. |
| API 672 | Packaged, Integrally Geared Centrifugal Air Compressors for Petroleum, Chemical, and Gas Industry Services. A simpler specification than API 617 for utility air compressors. |
| API 681 | Liquid Ring Vacuum Pumps and Compressors. Covers liquid ring machines used for vapor recovery and low-pressure applications. |
| ASME PTC 10 | Performance Test Code on Compressors and Exhausters. Defines the procedures for conducting and evaluating compressor performance tests, including corrections for test gas deviations from design conditions. Used for factory acceptance testing and field performance verification. |
| NACE MR0175 / ISO 15156 | Sulfide Stress Cracking Resistant Metallic Materials for Oilfield Equipment. Mandatory for compressors handling sour gas (H2S-containing). Defines material hardness limits, heat treatment requirements, and environmental severity levels. |
| ISO 10439 | Petroleum, Petrochemical and Natural Gas Industries - Axial and Centrifugal Compressors. The ISO equivalent to API 617, widely used outside North America. |
| ISO 13631 | Petroleum and Natural Gas Industries - Packaged Reciprocating Gas Compressors. |
Drivers
The choice of compressor driver significantly affects the overall system efficiency, CAPEX, operating flexibility, and site infrastructure requirements.
Gas Turbines
Gas turbines are the dominant driver for centrifugal compressors in pipeline and LNG service. They deliver high power density (up to 80+ MW per unit), high availability, and the ability to burn fuel gas directly from the process.
| Type | Characteristics | Examples |
|---|---|---|
| Aero-derivative | Lightweight, 35-42% efficiency, rapid start-up. Preferred for offshore platforms, FPSOs, and mid-size onshore plants. | GE LM2500, Rolls-Royce RB211 |
| Industrial (heavy-frame) | Built specifically for stationary service. Rugged, longer maintenance intervals, higher exhaust temperatures suitable for combined-cycle waste heat recovery. | GE Frame 5, Frame 7, Siemens SGT-700 |
Electric Motors
Electric motors are the preferred driver for refinery and gas plant compressors where reliable grid power is available. They run at 95-97% efficiency, require low maintenance, allow precise speed control through a VSD, produce no emissions at the point of use, and generate less noise than gas turbines.
Synchronous motors (up to 65 MW and beyond) drive large centrifugal compressors at fixed speed. Induction motors cover smaller duties. Motor-driven compressors require a separate starting method (reduced voltage, soft starter, or VSD) due to high inrush current.
Steam Turbines
Steam turbines serve refineries and petrochemical plants where high-pressure steam is available as a byproduct of process heating. They provide variable-speed capability inherently and can exhaust to a condenser (for maximum power) or to a lower-pressure steam header (back-pressure turbine) for process heating integration.
Gas Engines
Gas engines (reciprocating internal combustion engines fueled by natural gas) are the traditional driver for field gas compression in upstream operations. They suit remote locations where electric power is unavailable. Slow-speed gas engines (300-600 RPM) can be directly coupled to slow-speed reciprocating compressors, avoiding the need for a gearbox. Modern gas engines achieve 36-42% thermal efficiency.
Variable Speed Drives (VSDs)
Variable speed drives (also called variable frequency drives or VFDs) enable electric motor-driven compressors to operate at variable speed. They provide continuous capacity control without throttling or recycle, energy savings at reduced load (power follows the cube of speed in centrifugal machines), soft starting that eliminates inrush current issues, and precise process control.
VSDs are increasingly used for compressor applications up to about 40 MW. The main limitations are capital cost, physical size, harmonic distortion of the electrical supply, and efficiency losses in the drive electronics (typically 2-3%).
Materials Selection
Material selection for compressors depends on the gas composition, operating temperature and pressure, and applicable codes. Sour gas service (containing H2S) imposes stringent requirements under NACE MR0175 / ISO 15156.
Impellers and Rotors
| Component | Typical Materials | Notes |
|---|---|---|
| Centrifugal impeller (standard) | AISI 4140, AISI 4340 (forged low-alloy steel) | Quenched and tempered; max 22 HRC for NACE sour service |
| Centrifugal impeller (corrosive / high-strength) | 17-4 PH (UNS S17400), 15-5 PH stainless | Precipitation-hardened; good strength and corrosion resistance |
| Centrifugal impeller (subsea / sour) | Super duplex (UNS S32750), Inconel 718 | For extreme sour or CO2 environments |
| Axial blades | 12% Cr stainless (AISI 403, 410) | Good erosion and corrosion resistance |
| Reciprocating piston | Cast iron, aluminum alloy | Aluminum for lightweight non-lubricated service |
| Screw rotors | Ductile iron, 4140 steel, nitrided | Oil-flooded rotors may be coated for wear resistance |
Casings
| Service | Material | Standard |
|---|---|---|
| General hydrocarbon (moderate pressure) | Carbon steel, ASTM A216 WCB (cast), A105 (forged) | API 617 / 618 |
| High-pressure barrel casing | AISI 4130 / 4140 forged steel | API 617 barrel-type |
| Low-temperature (LNG refrigerant) | 3.5% Ni steel, 9% Ni steel, austenitic stainless | Charpy impact tested per API 617 |
| Sour service | Carbon steel meeting NACE MR0175 hardness limits | Max 22 HRC, stress-relieved |
Cylinder Liners and Valves (Reciprocating)
| Component | Material | Notes |
|---|---|---|
| Cylinder liner (standard) | Gray cast iron (ASTM A48) | Good wear properties, low cost |
| Cylinder liner (sour / corrosive) | Ni-Resist (austenitic ductile iron), nodular iron | Superior corrosion resistance in H2S environments |
| Piston rings | Cast iron, bronze, PTFE | PTFE for non-lubricated service |
| Packing rings | PTFE, carbon-filled PTFE, bronze | Non-lubricated: PTFE-based; lubricated: metallic |
| Valve plates (suction/discharge) | 17-4 PH stainless, 316 stainless, Inconel 625/718 | Inconel for corrosive or high-temperature services |
| Valve springs | Inconel X-750, 17-7 PH | Fatigue-rated for millions of cycles |
Design Considerations
Surge Control (Centrifugal Compressors)
Surge is the most dangerous operating condition for a centrifugal compressor. When flow drops below the surge line, the pressure developed by the impeller is insufficient to overcome the downstream pressure, causing the gas to flow backward through the impeller. This reversal is cyclical and violent, producing extreme vibration and thrust reversals, rapid temperature rise, seal and bearing damage, and potential shaft failure.
An anti-surge control system is mandatory. The system continuously monitors the compressor operating point (using suction flow, discharge pressure, and polytropic head) relative to the surge control line (set 10-15% to the right of the actual surge line for safety margin). When the operating point approaches the surge control line, a hot gas recycle valve (or cold gas bypass valve) opens to recirculate gas from discharge back to suction, maintaining the compressor above its minimum stable flow.
Modern anti-surge controllers (e.g., CCC, Compressor Controls Corporation) use algorithms that predict the operating point trajectory and open the recycle valve proactively, rather than waiting until the compressor reaches the surge line.
Pulsation Dampening (Reciprocating Compressors)
API 618 Design Approach 3 requires a comprehensive pulsation and mechanical analysis, typically performed by a specialist firm (e.g., Southwest Research Institute, Beta Machinery Analysis). The study covers four areas. First, an acoustic simulation models pressure pulsation levels throughout the suction and discharge piping system, pulsation dampener bottles, and cooler piping. Second, a mechanical natural frequency (MNF) analysis verifies that piping span natural frequencies do not coincide with compressor running speed harmonics. Third, a shaking force analysis calculates unbalanced forces on piping bends, tees, and valves due to pulsating flow. Fourth, dampener bottle sizing determines the volume and nozzle configuration of suction and discharge pulsation bottles to attenuate pulsations to acceptable levels (API 618 limits: typically 2-7% peak-to-peak of line pressure).
Intercooling
When gas is compressed through multiple stages, its temperature rises. Excessive discharge temperature degrades lubricant, accelerates seal wear, and can cause polymer formation in certain gas streams. Intercoolers (typically shell-and-tube or air-cooled heat exchangers) are installed between compression stages to cool the gas back to near-ambient temperature before the next stage.
Intercooling also improves thermodynamic efficiency: compressing cooler (denser) gas requires less work per unit mass. In multi-stage centrifugal compressors, interstage cooling may be accomplished through external coolers with return piping, sidestream injection of cooler gas (in refrigeration services), or integral intercoolers within the barrel casing (less common).
Capacity Control
Different compressor types use different methods to regulate capacity.
Centrifugal compressors most efficiently use speed variation, where flow is approximately proportional to speed and power follows the cube law. This requires a variable-speed driver (gas turbine, VSD-motor). Inlet guide vanes (IGVs) at the impeller eye pre-swirl the gas to reduce work input and shift the surge line, effective in the 80-100% capacity range. Hot gas recycle recirculates gas from discharge to suction; it is simple but energy-wasteful and serves primarily as anti-surge protection rather than steady-state capacity reduction. Suction throttling restricts flow through a control valve upstream, which is straightforward but lowers suction pressure and efficiency.
Reciprocating compressors can vary speed with engine drivers, though range is limited with motor drivers. Clearance pockets open additional dead volume in the cylinder head to reduce the effective swept volume; fixed-volume and variable-volume pockets are available. This is the most common capacity control method for motor-driven reciprocating compressors. Valve unloaders mechanically hold suction valves open on selected cylinders or ends, preventing compression and providing step-wise capacity reduction (e.g., 100%, 75%, 50%, 25%, 0% for a four-throw machine). Bypass/recycle returns gas from discharge to suction through a control valve, with the same energy penalty as centrifugal recycle.
Screw compressors use a slide valve — an axially movable valve within the compressor body that varies the effective rotor length, providing continuous capacity control from about 10% to 100%. Speed variation through VSD motors is also common.
Applications in Oil and Gas
Gas Gathering and Boosting
At the wellhead, natural gas may emerge at pressures too low for pipeline transport or further processing. Gathering compressors boost gas pressure from wellhead conditions (which may be as low as 0.5 - 5 bar) to gathering system pressure (typically 20 - 70 bar).
Small reciprocating units handle individual wells or small clusters and are often engine-driven for remote locations without grid power. Oil-flooded screw compressors have become increasingly popular in gas gathering because they tolerate liquids, take up little space, and operate simply. Small high-speed centrifugal compressors serve larger gathering stations where flow justifies the higher capital cost.
As fields deplete and wellhead pressure declines, compressor capacity requirements increase. Modular, skid-mounted compressor packages allow incremental capacity additions.
Gas Transmission Pipelines
Natural gas transmission over long distances (hundreds to thousands of kilometers) requires compressor stations spaced every 80-160 km to overcome pipeline frictional pressure losses. These stations typically use large centrifugal compressors rated 5-30 MW per unit, driven by gas turbines, with pressure ratios of 1.3 to 1.6 per station. Multiple units run in parallel for redundancy and turndown flexibility. The gas turbine drivers burn pipeline gas as fuel, typically consuming 3-5% of the gas throughput for compression.
Pipeline compressors operate at near-constant speed and pressure ratio, a duty profile that centrifugal machines handle well. The compressor casing is typically a barrel type (vertically split) due to the high pressure and the need for gas-tight joints.
Gas Processing Plants
Gas processing plants separate natural gas liquids (NGLs), remove contaminants (CO2, H2S, water), and produce sales-quality gas. Compressor services in gas processing plants include inlet compressors that boost incoming gas from the gathering system to plant operating pressure; refrigeration compressors that drive the cooling cycles (propane, ethylene, mixed refrigerant) for NGL extraction, typically as multi-stage centrifugal machines in back-to-back or integrally geared configurations; residue gas compressors that compress the lean gas from the demethanizer to pipeline delivery pressure; and acid gas compressors that compress removed H2S/CO2 for reinjection or sulfur recovery.
LNG Liquefaction
LNG plants represent the most demanding compressor application in the industry. The liquefaction process requires very large refrigerant compressors (propane, mixed refrigerant, nitrogen) with power demands of 30-80+ MW per string.
Combined axial-centrifugal trains place the axial section on the high-volume, low-pressure suction stages and the centrifugal section on the higher-ratio discharge stages, maximizing efficiency at very high flows. Pure centrifugal trains serve smaller-scale LNG or cases where axial compressor complexity is not justified. Common drivers are industrial gas turbines (GE Frame 7EA, Frame 9E, Siemens SGT-800), large aero-derivatives (GE LM6000), and increasingly, all-electric drives using large VSD-motor combinations.
A single LNG train may have 3-4 compressor strings (propane, MR low-pressure, MR high-pressure, end-flash) with a combined power demand of 150-250 MW.
Refinery Service
Refineries employ compressors in numerous process units. Recycle gas compressors in hydroprocessing units (hydrotreater, hydrocracker) use centrifugal machines to recirculate hydrogen-rich gas at pressures of 50-200 bar; these are high-pressure barrel-type centrifugal compressors per API 617. Wet gas compressors in the FCC unit handle the cracked gas from the reactor overhead — the gas is wet (contains hydrocarbon liquids) and corrosive (contains H2S). Reformer recycle compressors in catalytic reforming units circulate hydrogen using centrifugal machines. The FCC main air blower, an axial or centrifugal machine (often the largest single machine in the refinery), provides combustion air to the FCC regenerator at flows up to 500,000 Am3/h.
Gas Re-Injection
Re-injection compressors are among the highest-pressure compressors in the industry. They compress associated gas or produced gas for injection back into the reservoir to maintain reservoir pressure and enhance oil recovery. Discharge pressures can reach 350-700 bar, handled by multi-stage reciprocating compressors (often 4-6 stages) for the highest pressures, or by centrifugal compressors for high-flow, moderate-pressure re-injection (up to ~250 bar). Materials must be sour-service qualified if the gas contains H2S.
Re-injection compressor trains are critical machines with high reliability requirements. Sparing (N+1 configuration) and extensive condition monitoring (API 670) are standard.
Frequently Asked Questions
What is the difference between a compressor and a pump?
A compressor increases the pressure of a gas (compressible fluid), while a pump increases the pressure of a liquid (essentially incompressible). Because gases are compressible, the volume, temperature, and density of the gas change significantly during compression, making the thermodynamic analysis more complex than for pumps. Compressors generally require more power per unit of pressure rise than pumps due to the compressibility work.
How do I choose between a centrifugal and reciprocating compressor?
The primary factors are flow rate and pressure ratio. For high flow rates (above roughly 5,000 Am3/h) with moderate pressure ratios, centrifugal compressors are generally preferred due to continuous flow, lower maintenance, and compact design. For low-to-moderate flow rates with high pressure ratios (especially above 100:1), reciprocating compressors are the standard choice. Gas composition, site conditions (availability of drivers, power), and OPEX considerations also play a role.
What causes compressor surge and how is it prevented?
Surge occurs in centrifugal and axial compressors when the gas flow drops below a critical minimum, causing the gas to reverse direction through the impeller. It is prevented by an anti-surge control system that monitors the operating point relative to the surge line and opens a recycle valve to maintain minimum flow when the operating point approaches the surge limit. Every centrifugal and axial compressor installation requires a dedicated anti-surge controller.
Why are pulsation dampeners needed for reciprocating compressors?
Reciprocating compressors produce pulsating flow because gas is discharged in discrete bursts with each piston stroke. These pressure pulsations can cause piping fatigue failures, inaccurate flow measurements, and acoustic resonance. Pulsation dampeners (large vessels at suction and discharge) attenuate these oscillations to acceptable levels, as required by API 618.
What is a dry gas seal?
A dry gas seal (DGS) is a non-contacting, gas-lubricated mechanical face seal used on centrifugal compressor shafts. It uses a thin film of clean, dry gas (typically nitrogen or process gas) between the rotating and stationary seal faces. DGS replaced oil-film seals in most modern compressor designs, eliminating oil contamination of the process gas and reducing maintenance and operating costs.
What is NACE MR0175 and when does it apply to compressors?
NACE MR0175 (now ISO 15156) defines material requirements for sour service (gas containing hydrogen sulfide, H2S). It applies to all compressor wetted components when the partial pressure of H2S in the gas exceeds certain thresholds. The standard limits material hardness (typically 22 HRC maximum for carbon and low-alloy steels), mandates specific heat treatment procedures, and restricts certain alloys to prevent sulfide stress cracking (SSC) and hydrogen-induced cracking (HIC).
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