AMPP ICS cheat sheet

CO2 corrosion: dissolved carbonic acid (H2CO3) cathodically reduces; rate peaks near 60-80 C where protective FeCO3 films lose stability.

H2S corrosion: sulfide films (mackinawite, pyrrhotite) may be protective or non-protective; >0.05 psi H2S partial pressure flags sour service per NACE MR0175/ISO 15156.

Sweet vs sour: CO2-dominated systems form FeCO3; H2S-dominated form FeS; mixed systems produce scale competition that often degrades protectiveness.

Galvanic corrosion requires dissimilar metals in electrolytic contact; anode is the more active (lower potential) metal; severity scales with potential difference and cathode area ratio (cathode:anode area increases attack on anode).

Erosion-corrosion: mechanical film removal raises bare-metal corrosion rate; critical velocity depends on sand, geometry, and flow regime (slug, annular, stratified).

Microbially influenced corrosion (MIC): sulfate-reducing bacteria generate H2S; acid-producing bacteria lower local pH; sessile populations in biofilms drive localized pitting.

Oxygen corrosion: even ppb-level O2 in produced water drives rapid attack; O2 ingress is a top cause of unexpected internal failures in water injection systems.

Crevice/underdeposit corrosion: differential aeration cells develop under scale, sand, or debris; pits deepen because the occluded anode is small relative to the external cathode.

Corrosion rate increases with temperature up to a maximum (FeCO3 solubility minimum), then falls as protective scale forms; model temperature dependence explicitly rather than assuming monotonic increase.

CO2 partial pressure (pCO2) drives carbonic acid concentration; common screening uses pCO2 > 7 psi as a sweet-corrosion trigger.

pH shifts carbonate/bicarbonate equilibria and scale stability; higher pH generally lowers CO2 corrosion rate but raises risk of carbonate scale and, at high pH, caustic/alkaline cracking.

Wall shear stress and flow regime govern film removal and mass transfer; stratified low-velocity flow promotes water dropout and underdeposit corrosion.

Water cut, water chemistry (chlorides, bicarbonate, calcium, sulfate), and condensate ratio determine corrosivity; chloride content reduces FeCO3 stability and raises pitting risk.

Bacterial activity is temperature-bounded: SRB generally active below ~60-70 C; sessile counts and ATP or qPCR better indicate MIC risk than planktonic samples.

Oxygen ingress sources include poorly deaerated injection water, vacuum service, and tank blanketing failures; even trace O2 accelerates both general and pitting attack.

Pressure and partial pressures of acid gases (CO2, H2S) determine phase behavior and whether water is condensed as a separate liquid phase.

H2S is toxic at low ppm (IDLH 100 ppm); odor fatigue occurs above ~100 ppm; rely on personal monitors and escape sets, not smell.

H2S is heavier than air and accumulates in low points, pits, sumps, and tanks; confined-space entry requires atmospheric testing before and during entry.

Sour service materials must meet NACE MR0175/ISO 15156; non-compliant materials risk sulfide stress cracking and catastrophic failure.

CO2 is an asphyxiant and displaces O2; O2-deficient atmospheres (<19.5% O2) require supplied air, not filter respirators.

Flammable atmospheres: LEL/UEL monitoring is required where hydrocarbons are present; hot work permits and gas testing precede ignition sources.

Pressure releases during sampling, pigging, or well intervention expose personnel to high-velocity fluid and gas; isolation, depressurization, and lockout/tagout are prerequisites.

Corrosion-induced wall loss reduces pressure containment; fitness-for-service assessment (e.g., ASME B31G, API 579) determines safe operating limits before continued service.

Chemical handling: corrosion inhibitors and biocides require SDS review, PPE, and spill response planning; some inhibitors are toxic or flammable.

Coupon weight loss gives average general corrosion rate; localized attack (pitting) is assessed by pit depth and pit density, not just mass loss.

Electrical resistance (ER) probes give real-time metal loss trends but are less sensitive to localized attack than coupons.

Linear polarization resistance (LPR) measures instantaneous corrosion rate; requires conductive, aqueous electrolyte and is affected by scale and inhibitor films.

Trend interpretation: baseline vs treated comparison, slope changes, and step changes flag inhibitor or process upsets; single-point data are insufficient for diagnosis.

Iron counts in produced water correlate with corrosion rate; spikes indicate increased corrosion or solids carryover; trend with production rate and water chemistry.

Inspection data (UT, ILI) and monitoring data must be reconciled; discrepancies indicate probe placement, sampling, or inspection error and require verification.

Pitting identification: pit depth, aspect ratio, and distribution; underdeposit and MIC pits are typically compact and deep; erosion pits are elongated in flow direction.

Data quality checks: calibration records, probe exposure time, and sample representativeness; missing metadata invalidates trend analysis.

Carbon steel + CO2: film-forming amine or imidazoline inhibitors; performance depends on partitioning into water and persistence under shear.

Sour service: select materials per NACE MR0175/ISO 15156; use corrosion-resistant alloys (CRA) or inhibitor systems validated for H2S partial pressure and pH.

Water injection: deaeration, oxygen scavengers, and biocide programs; SRB control via biocide and nitrate/nitrite treatments.

Material selection: CRAs (13Cr, duplex, superduplex, nickel alloys) trade capital cost for reduced mitigation and inspection burden; verify chloride SCC resistance.

Internal coatings and linings isolate steel from electrolyte; holiday/defect inspection is essential because coating failures localize attack.

Cathodic protection is not applicable internally to isolated piping; internal CP is limited to specific geometries (e.g., seawater pipelines with sacrificial anodes).

pH stabilization reduces CO2 corrosion by promoting protective FeCO3; requires water chemistry control and monitoring.

Biocide selection considers biofilm penetration, compatibility with other chemicals, and environmental discharge limits; alternating actives reduces resistance.

Corrosion-resistant alloy cladding or solid CRA replaces inhibitor dependence where inhibitor logistics or shear are problematic.

Internal coating plus CP or inhibitors may be combined for high-risk segments; verify compatibility and inspect holidays.

Monitoring alternatives: coupons (retrievable), ER probes, LPR probes, ultrasonic sensors, and non-intrusive wall-thickness monitoring.

Non-intrusive ultrasonic monitoring enables periodic or continuous wall-thickness tracking without hot work or shutdown.

Pigging with instrumented (smart) pigs provides inline inspection (ILI) for metal loss mapping; requires piggable geometry.

Sampling and analysis: water chemistry, iron counts, bacterial counts, and dissolved gas analysis; sample points must be representative.

Design changes: increase wall thickness, add corrosion allowance, improve flow regime to avoid low spots, and provide drain and vent points.

Risk-based inspection (RBI) allocates inspection resources by likelihood and consequence; aligns monitoring with risk ranking.

Failure analysis sequence: collect background, inspect failure site, characterize morphology, analyze deposits and fluids, and test hypotheses.

Morphology clues: uniform thinning = general corrosion; deep compact pits = MIC or underdeposit; grooving = erosion-corrosion or flow-accelerated corrosion.

Deposit analysis (XRD, SEM/EDS) identifies corrosion products (FeCO3, FeS, Fe3O4) and scale protectiveness.

Metallography distinguishes cracking modes: sulfide stress cracking, hydrogen-induced cracking, and chloride SCC have distinct paths and morphology.

Root cause requires distinguishing mechanism from contributing factors (e.g., inhibitor failure, process upset, material non-conformance).

Verify material conformance to specification (chemistry, hardness, heat treatment) before attributing failure to environment alone.

Correlate failure timing with operating history (start-up, shutdown, water breakthrough, chemical injection interruptions).

Document findings with photos, measurements, and chain of custody for legal and regulatory defensibility.

Program elements: risk assessment, mitigation selection, monitoring, inspection, data management, and periodic review.

Define key performance indicators (KPIs): corrosion rate targets, inhibitor availability, inspection coverage, and corrective action closure.

Periodic review cycles (e.g., annual) reassess risk based on monitoring trends and process changes; update mitigation and inspection plans.

Management of change (MOC) ensures process, material, or chemical changes trigger re-evaluation of corrosion risk.

Roles and responsibilities: corrosion engineer, operations, inspection, and management accountability for program execution.

Documented procedures for sampling, monitoring, and inspection ensure consistency and defensibility.

Corrective action tracking closes the loop between findings and mitigation; overdue actions escalate risk.

Budget and resource planning links corrosion control spend to risk reduction and life-cycle cost.

Data management: centralized database with metadata (location, date, method, conditions) enables trend analysis and audit.

Data validation: check calibration, exposure time, and representativeness before using data for decisions.

Assessment integrates monitoring, inspection, and process data; single-source conclusions are unreliable.

Recommendations must be specific, prioritized by risk, and assigned owners with due dates.

Implementation tracking verifies actions are completed and effective; effectiveness is confirmed by follow-up monitoring.

Reporting to management summarizes risk status, trends, and resource needs.

Data retention supports regulatory audits and failure investigations; define retention periods per regulation.

Regulatory frameworks: pipeline safety regulations (e.g., 49 CFR 192/195), API RP 1160, and NACE/AMPP standards define integrity management requirements.

Records must demonstrate corrosion control: monitoring data, inspection reports, mitigation records, and corrective actions.

Integrity management programs require risk assessment, baseline assessment, and periodic reassessment.

Record retention periods vary by jurisdiction; retain at least the period required by regulation and for failure investigation needs.

Audit readiness: organized, retrievable, and traceable records reduce compliance risk.

Incident reporting obligations may apply to releases and failures; know reporting thresholds and timelines.

Training and competency records support program credibility and regulatory compliance.