Analysis of the Impact of Carbon Dioxide Concentration on Pumps: Mechanisms, Testing, and Material E

Carbon dioxide concentration plays a critical role in determining the service life, hydraulic performance, and material integrity of industrial pumps operating in CO2-rich environments. Understanding how dissolved and gaseous CO2 interacts with pump components enables engineers to select appropriate materials, predict corrosion behavior, and implement effective maintenance strategies. This article provides a comprehensive analysis of CO2 concentration effects on pumps, covering corrosion mechanisms, testing methodologies, relevant standards, and practical applications across oil and gas, carbon capture, and process industries.

Technical Overview

Carbon dioxide is one of the most chemically aggressive media encountered in pump applications across the oil and gas, chemical, food and beverage, and carbon capture industries. When CO2 dissolves in water or aqueous process fluids, it forms carbonic acid (H2CO3), which lowers the pH of the fluid and drives a corrosion mechanism commonly known as sweet corrosion or CO2 corrosion. Unlike strong mineral acids, carbonic acid attacks steel surfaces through a complex interplay of anodic iron dissolution and cathodic hydrogen evolution, often producing localized damage such as mesa attacks, pitting, and flow-accelerated corrosion on impellers, casings, and shafts.

The severity of CO2 attack on pump components is governed by several interrelated factors: the partial pressure of CO2, the temperature of the fluid, the flow velocity, the presence of water (free water is required for corrosion to occur), the chloride content, and the protectiveness of corrosion product films such as iron carbonate (FeCO3). Industry practice commonly classifies CO2 severity by partial pressure: below 0.5 bar is generally considered mild, 0.5 to 2 bar moderate, and above 2 bar severe, although these thresholds must always be validated against actual operating temperatures and fluid chemistry. At elevated temperatures, iron carbonate films can become protective and reduce corrosion rates, whereas at intermediate temperatures film breakdown can lead to accelerated localized attack.

Beyond electrochemical corrosion, high CO2 concentrations affect pumps in additional ways. Elastomeric seal elements, O-rings, and gaskets can experience swelling, softening, or permeation-induced blistering when exposed to carbonated fluids or dense CO2 phases, and rapid gas decompression can cause explosive decompression failure in elastomers. In supercritical CO2 applications, such as power cycles and injection systems, solvent effects on polymers and lubricants, changes in fluid density near the critical point, and cavitation behavior near the saturation pressure all influence pump reliability. A systematic analysis of CO2 concentration effects therefore requires a combination of environmental characterization, material degradation testing, and hydraulic performance verification.

Testing Samples

Metallic Pump Components

Representative metallic samples include impellers, volute casings, wear rings, shafts, shaft sleeves, and fasteners fabricated from commonly specified pump materials such as cast iron, carbon steel, martensitic stainless steel (UNS S41000), austenitic stainless steel (UNS S31600), duplex stainless steel (UNS S31803/S32205), super duplex stainless steel (UNS S32750), and nickel-based alloys such as UNS N06625. Coupons machined from the same heat and heat treatment condition as production components are used for controlled exposure testing.

Sealing and Polymeric Materials

Sealing samples include mechanical seal faces (carbon graphite, silicon carbide, tungsten carbide), secondary seals and O-rings in nitrile rubber (NBR), ethylene propylene diene monomer (EPDM), fluoroelastomer (FKM), and perfluoroelastomer (FFKM), together with PTFE-based gaskets and thermoplastic pump components in PP, PVDF, and PEEK. These materials require dedicated compatibility evaluation because polymeric degradation mechanisms under CO2 exposure differ fundamentally from metallic corrosion.

Coated and Surface-Treated Specimens

Where corrosion-resistant coatings or surface treatments are employed, such as electroless nickel plating, hard chrome, thermal spray coatings, or epoxy internal linings, coated test panels and coated pump sections are included to evaluate coating adhesion, permeability, and barrier performance under CO2-containing conditions.

Testing Items

A complete CO2 concentration impact analysis on pumps typically encompasses the following evaluation items:

• CO2 concentration and partial pressure determination in the process gas and dissolved CO2 content in the liquid phase
• General corrosion rate measurement of metallic materials under simulated service conditions
• Localized corrosion assessment, including pitting depth, mesa attack, and crevice corrosion evaluation
• Electrochemical characterization, including corrosion potential, polarization resistance, and Tafel constants
• Corrosion product film analysis, including film morphology, composition, and stability
• Tensile strength, yield strength, elongation, and hardness changes after CO2 exposure
• Impact toughness evaluation to detect embrittlement or degradation
• Elastomer compatibility testing, including volume swell, mass change, hardness change, tensile retention, and compression set after immersion
• Rapid gas decompression resistance of elastomeric seals in CO2 service
• Hydraulic performance verification, including head, flow rate, efficiency, and NPSH behavior in carbonated media
• Cavitation erosion resistance under CO2-saturated conditions, where dissolved gas can alter cavitation inception and collapse intensity
• Seal integrity and leakage rate verification under pressurized CO2 environments
• Welded joint and heat-affected zone corrosion evaluation for fabricated pump components

Testing Methods

Environmental and Concentration Characterization

CO2 concentration in gas streams is measured using infrared gas analysis or gas chromatography, while dissolved CO2 and carbonate species in liquid streams are quantified by titration according to standard water analysis practices or by total inorganic carbon analysis. Temperature, pH, chloride content, and oxygen level are recorded simultaneously because these parameters strongly modify the corrosivity of a given CO2 concentration. The effective CO2 partial pressure is calculated from system pressure and gas composition to establish the environmental severity class used in material selection frameworks such as API 610 and ISO 15156 guidance for oilfield fluids.

High-Pressure Autoclave Immersion Testing

Weight-loss coupon exposure is performed in high-pressure, high-temperature autoclaves that replicate the CO2 partial pressure, temperature, and fluid chemistry of the actual pump service. Testing follows the general principles of ASTM G31 for laboratory immersion corrosion testing of metals, with pre- and post-exposure cleaning and evaluation conducted per ASTM G1. Duplicate and triplicate coupons are exposed for durations sufficient to capture steady-state behavior, and corrosion rates are computed and reported in millimeters per year. Suspended coupons, rotating cage assemblies, or jet impingement fixtures may be used to incorporate the flow effect that is so significant for pump internal components.

Electrochemical Corrosion Testing

Linear polarization resistance measurements per ASTM G59, potentiodynamic polarization scans, and electrochemical impedance spectroscopy are conducted in CO2-saturated brines at controlled temperature and pressure to obtain instantaneous corrosion rates and film formation kinetics. These techniques allow rapid screening of material-environment combinations and quantitative comparison of alloys and inhibitors. Three-electrode cells with a reference electrode suited to high-pressure CO2 service are employed, and dissolved CO2 is continuously verified to maintain saturation throughout the test.

Mechanical and Metallurgical Evaluation

Post-exposure mechanical testing per ASTM E8 or ISO 6892 determines whether CO2-related degradation has affected structural integrity, while hardness testing per ASTM E18 identifies carburization, hydrogen effects, or softening. Microstructural examination, pitting depth measurement, and corrosion product identification are performed using optical microscopy, scanning electron microscopy with energy-dispersive X-ray spectroscopy, and X-ray diffraction. Pitting severity is assessed according to ASTM G46 practices.

Elastomer and Polymer Compatibility Testing

Polymeric seal materials are immersed in CO2-saturated fluids or exposed to dense CO2 phases following the general approach of ASTM D471 for fluid resistance of rubbers, measuring volume change, mass change, hardness change per ASTM D2240, and tensile property retention per ASTM D412. Rapid gas decompression testing subjects pressurized specimens to controlled depressurization cycles to screen for blistering and cracking, which is essential for mechanical seals and O-rings in CO2 injection and carbonation service.

Pump Performance and Integrity Verification

Hydraulic performance testing per ISO 9906 verifies head, flow, efficiency, and NPSH characteristics, confirming that material condition and surface roughness changes from CO2 exposure have not degraded performance beyond acceptable limits. Hydrostatic pressure testing of casings and leakage testing of assembled seals are performed on refurbished or qualification pumps. For electrically driven units, insulation system evaluation per IEC 60034 series requirements may accompany the mechanical program when the pump operates in humid CO2-laden atmospheres.

Applications

CO2 concentration impact analysis supports critical engineering decisions across a wide range of industries:

• Oil and gas production, where produced water and formation gas containing CO2 require corrosion-resistant pump metallurgy for artificial lift, water injection, and transfer pumps
• CO2 enhanced oil recovery (EOR), in which high-pressure CO2 injection pumps and stream mixing equipment operate under severe corrosive and dense-phase conditions
• Carbon capture, utilization, and storage (CCUS), where amine circulation pumps, CO2 compression and injection pumps, and transportation systems face high CO2 partial pressures and oxygen or sulfur oxide contaminants
• Supercritical CO2 power cycles and heat pump systems, requiring specialized turbomachinery and seal evaluations near the critical point
• Food and beverage processing, including carbonation dosing pumps, syrup transfer, and CIP systems handling carbonated products
• Brewing and fermentation industries, where wort, yeast, and beer transfer pumps operate in CO2-rich, low-pH environments
• Municipal and industrial water treatment, including recarbonation pumps that readjust pH after lime softening and dosing systems for acid neutralization
• Chemical and fertilizer plants handling carbonation stages, ammonium carbonate, and urea plant condensates
• Marine and offshore applications, where seawater with dissolved CO2 and chlorides creates an aggressive combination for firewater, cooling, and ballast pumps

FAQ

At what CO2 concentration does pump corrosion become a significant concern?

Corrosion risk is driven by CO2 partial pressure rather than concentration alone. As a general guideline widely used in the petroleum industry, a CO2 partial pressure below 0.5 bar is considered low risk, 0.5 to 2 bar moderate, and above 2 bar high risk for carbon steel equipment. However, free water must be present for corrosion to occur, and temperature, flow velocity, pH, and chloride content can shift these thresholds substantially. A site-specific analysis combining environmental data with coupon or electrochemical testing is always recommended before finalizing material selection.

How does temperature influence CO2 corrosion of pump materials?

Temperature has a non-linear effect. Below approximately 60 degrees Celsius, corrosion rates generally increase with temperature because reaction kinetics accelerate. Between roughly 60 and 150 degrees Celsius, protective iron carbonate films may form on carbon steel and reduce the corrosion rate, but at higher flow velocities these films can be mechanically damaged, producing severe localized mesa attack. Above approximately 150 degrees Celsius, film stability improves for carbon steel, while austenitic and duplex stainless steels maintain passive behavior across broad temperature ranges in the absence of chlorides.

Which materials offer the best resistance for pumps in CO2-rich service?

For moderate CO2 severity, 316-type austenitic stainless steel often performs well when chloride content is low. In CO2 plus chloride environments, such as produced water or seawater, duplex and super duplex stainless steels provide superior resistance to pitting and crevice corrosion. Nickel-based alloys are specified for the most severe combinations of CO2, chlorides, and elevated temperature. Elastomeric seals should be selected based on dedicated compatibility testing, with FKM and FFKM grades frequently chosen for high-pressure CO2, noting that rapid gas decompression resistance must be verified for dense-phase applications.

How does dissolved CO2 affect cavitation behavior in pumps?

Dissolved gases, including CO2, can act as nucleation sites that lower the cavitation inception threshold, meaning cavitation may begin at a higher NPSH available than would be expected with degassed liquid. In addition, gas content changes the vapor and gas release dynamics during pressure drops across the impeller eye, which can alter head performance and increase vibration. Ensuring adequate NPSH margin and verifying performance with the actual carbonated fluid are important design safeguards.

Can corrosion inhibitors eliminate the need for corrosion-resistant pump materials?

Inhibitors can substantially reduce general corrosion rates in pipeline and vessel service, but their effectiveness inside high-svelocity pump internals is less reliable because turbulent shear can strip protective films and inhibitor filming may be incomplete on rotating components. Inhibitor programs should therefore be treated as a complement to, not a substitute for, appropriately rated metallurgy in severe CO2 service, and their performance should be confirmed through flow-accelerated coupon or loop testing rather than static immersion alone.

What standards are relevant to evaluating pumps in CO2 service?

Key references include ASTM G31 for immersion corrosion testing, ASTM G1 for coupon cleaning and evaluation, ASTM G59 for polarization resistance measurements, ASTM G46 for pitting evaluation, ASTM D471 for elastomer fluid resistance, ASTM D412 for rubber tensile properties, ISO 9906 for pump hydraulic performance acceptance testing, API 610 for centrifugal pumps in petroleum and natural gas industries, API 682 for mechanical seal systems, and ISO 15156 guidance on materials for oilfield fluids containing acidic gases. Testing performed by accredited third-party laboratories in accordance with these standards provides defensible, comparable results for material qualification and remaining life assessment.

How frequently should pumps in CO2 service be inspected?

Inspection intervals should be established based on measured or predicted corrosion rates, the consequence of failure, and the availability of condition monitoring data. A risk-based approach that combines ultrasonic thickness monitoring of casings, vibration analysis for impeller erosion detection, seal leakage trending, and periodic bore scope examination of internal passages allows operators to detect accelerated degradation before functional failure. When measured corrosion rates exceed design allowances, intervals should be shortened or material upgrades implemented at the next overhaul.