Hydrogen Probe

Key Takeaways

• The physical basis of hydrogen probe measurement is the permeability of atomic hydrogen through the iron lattice of carbon steel: in a sour environment (containing H2S at any partial pressure, from trace amounts to full sour conditions above 0.05 psia H2S per NACE MR0175/ISO 15156), the corrosion reaction at the inner steel surface generates atomic hydrogen (H) as a cathodic product rather than molecular hydrogen (H2) because the H2S molecule poisons the metal surface and inhibits the recombination of atomic hydrogen to molecular hydrogen (the Volmer recombination step is blocked); the atomic hydrogen atoms, being small (diameter approximately 0.53 angstroms), can diffuse through the steel lattice and accumulate at internal defects (inclusions, laminations, grain boundaries, voids from rolling defects) where they recombine to H2, generating internal pressure that can exceed 100 MPa (1,000 bar) at hydrogen trapping sites and initiate cracks (the mechanism of hydrogen-induced cracking, HIC); the fraction of the surface-generated atomic hydrogen that diffuses through the steel to the outer surface versus that which recombines at trapping sites or escapes back into the process fluid is determined by the hydrogen diffusivity (D) and the trapping site density in the steel; a higher outer-surface hydrogen flux measured by the probe indicates a higher rate of atomic hydrogen generation at the inner surface and hence a higher risk of HIC initiation and propagation; clean, low-inclusion steels (HIC-resistant steels meeting NACE TM0284 requirements with low sulfur content below 0.002 percent and calcium treatment for inclusion shape control) have fewer hydrogen trapping sites and show lower hydrogen probe readings for the same inner-surface corrosion rate, and have lower HIC susceptibility than conventional structural steels.
• Electrochemical hydrogen probes (the most widely used type in continuous monitoring applications) operate by maintaining a thin steel membrane (typically 1 to 3 mm thick, welded into the pipe wall as a patch fitting or installed as a cylindrical probe in a bypass line or coupon holder) at a constant anodic potential (typically 200 to 300 mV above the equilibrium hydrogen electrode potential in an alkaline electrolyte) on the outer surface, using a potentiostat to control the potential and measure the resulting oxidation current; atomic hydrogen that permeates through the membrane from the inner (process) side to the outer (electrolyte) side is oxidized at the outer surface to proton and electron: H --> H^+ + e^-, generating a measurable current that is directly proportional to the hydrogen flux (by Faraday's law, I = n*F*J*A, where n=1 electron per hydrogen atom, F is Faraday's constant, J is the hydrogen flux in mol/m^2/s, and A is the membrane area in m^2); the background current (from electrochemical reactions other than hydrogen oxidation) is subtracted by a baseline measurement before process fluid exposure; modern electrochemical hydrogen probes (available from Cosasco, Metal Samples, and Corrosion Instruments) provide a 4-20 mA analog output proportional to hydrogen flux that can be directly connected to a data acquisition system for continuous monitoring and trending.
• Hydrogen probe placement is critical to obtaining representative measurements of the hydrogen charging environment at the most corrosion-vulnerable locations: in oil and gas production pipelines and facilities, hydrogen probe locations should be selected based on corrosion engineering analysis to identify the locations of highest H2S activity, lowest pH, highest velocity, and highest potential for liquid accumulation (low points, slugging locations) that are the primary risk sites for H2S corrosion and hydrogen charging; NACE SP0775 (Preparation, Installation, Analysis, and Interpretation of Corrosion Coupons in Oilfield Operations) and NACE SP0192 (Monitoring Corrosion in Oil and Gas Production with Iron Counts) provide guidance on probe placement philosophy; downstream of choke valves (where pressure reduction concentrates H2S in the liquid phase), at the bottom of vertical risers (where liquid accumulates), and at bends and elbows (where turbulence increases the corrosion rate) are all high-priority locations for hydrogen probe installation in sour service; multiple probes at different locations in a production system allow comparison of hydrogen charging rates across the system and identification of the highest-risk locations for inspection and maintenance priority; sudden increases in hydrogen probe current at a specific location indicate either an increase in H2S concentration, pH reduction (from CO2 ingress or organic acid production), or breakdown of the corrosion inhibitor film at that location, triggering investigation and remediation before hydrogen-induced cracking initiates.
• Correlation between hydrogen probe flux and actual HIC damage must be established empirically for a given steel grade and process environment: laboratory testing per NACE TM0284 (Evaluation of Pipeline and Pressure Vessel Steels for Resistance to Hydrogen-Induced Cracking) exposes coupons of the steel to a standardized sour test solution (5 percent NaCl + 0.5 percent acetic acid saturated with H2S at 1 atm, the NACE standard solution A) and measures the crack area ratio (CAR), crack length ratio (CLR), and crack sensitivity ratio (CSR) after 96 hours of exposure; separately, an electrochemical hydrogen probe can measure the hydrogen flux during the same exposure to establish the flux associated with the test conditions; the ratio of the field hydrogen flux to the laboratory test flux provides a scaling factor to estimate the HIC risk from field probe readings relative to the known-damaging conditions of the laboratory test; this correlation is material-specific (different steel grades with different microstructures, inclusion densities, and sulfur contents have different susceptibilities at the same hydrogen flux) and environment-specific (different H2S partial pressures, pH levels, and chloride concentrations produce different atomic hydrogen generation efficiencies for the same bulk chemistry); a rigorous hydrogen probe monitoring program integrates the probe readings with periodic field inspection (UT scanning, EMAT, magnetic flux leakage inspection) to verify that the predicted HIC risk from the probe data corresponds to the actual damage accumulation in the pipe wall.
• Hydrogen probe data is used in corrosion management programs as a key performance indicator (KPI) for chemical injection effectiveness: corrosion inhibitors in sour service protect the steel surface by forming a physically adsorbed or chemically bonded film that reduces the rate of the corrosion reaction and the consequent atomic hydrogen generation; the effectiveness of the inhibitor film is directly reflected in the hydrogen probe reading -- a well-inhibited surface generates less atomic hydrogen than an uninhibited or poorly inhibited surface under the same bulk fluid chemistry; hydrogen probe monitoring therefore provides a real-time measure of inhibitor film quality (complementary to corrosion rate coupons, which integrate damage over the coupon exposure period and cannot distinguish periods of good inhibition from periods of breakdown); standard operational practice in sour production systems is to establish a hydrogen flux baseline for the uninhibited system, then verify that the corrosion inhibitor program achieves a target flux reduction (typically 80 to 95 percent reduction from baseline in actively sour systems), with the hydrogen probe providing the continuous feedback needed to detect inhibitor depletion, under-dosing, or incompatibility with other production chemicals that would otherwise not be apparent until HIC damage was detected in the next scheduled inspection.