1. Overview
Corrosion rate quantifies metal loss velocity due to electrochemical reactions with the environment. Accurate measurement enables remaining life prediction, inspection scheduling, and inhibitor optimization.
Integrity Management
Remaining Life
Calculate pipe retirement dates and set inspection intervals per API 570/580.
Material Selection
CRA Upgrade
Determine when carbon steel requires upgrade to corrosion-resistant alloys.
Chemical Treatment
Inhibitor Dosing
Optimize inhibitor concentration using coupon monitoring data.
Economics
Cost Analysis
Compare inhibition costs vs. material upgrades over project life.
Corrosion Rate Units
| Unit | Application | Conversion |
|---|---|---|
| mpy (mils/year) | US industry standard | 1 mpy = 0.0254 mm/year |
| mm/year | SI/international standard | 1 mm/year = 39.37 mpy |
| μm/year | Low corrosion rates, CRAs | 1 μm/year = 0.03937 mpy |
| g/m²·day | Weight loss basis | Material-dependent |
Industry Impact: US DOT reports over 1,000 corrosion-related pipeline incidents annually, costing billions in damages. Proper corrosion management prevents 40–60% of these failures.
2. Corrosion Mechanisms
All aqueous corrosion is electrochemical, requiring anodic metal dissolution and cathodic reduction reactions occurring simultaneously at different surface sites.
Fundamental Electrochemistry
Electrochemical Reactions:
Anodic (oxidation): Fe → Fe²⁺ + 2e⁻
Cathodic (reduction):
Aerated neutral: O₂ + 2H₂O + 4e⁻ → 4OH⁻
Acidic/deaerated: 2H⁺ + 2e⁻ → H₂
Overall (aerated): 2Fe + O₂ + 2H₂O → 2Fe(OH)₂ → rust
Corrosion rate from current density:
CR (mpy) = 0.1288 × EW × i_corr / ρ
Where:
i_corr = corrosion current density (μA/cm²)
EW = equivalent weight (g/equivalent)
ρ = metal density (g/cm³)
Sweet Corrosion (CO₂)
Carbon dioxide dissolves in water forming carbonic acid, the primary corrosion mechanism in gas production and gathering systems.
CO₂ Corrosion Chemistry:
CO₂ + H₂O ⇌ H₂CO₃ (carbonic acid, pKa ≈ 6.4)
H₂CO₃ ⇌ H⁺ + HCO₃⁻
Anodic: Fe → Fe²⁺ + 2e⁻
Cathodic: 2H₂CO₃ + 2e⁻ → H₂ + 2HCO₃⁻
Scale: Fe²⁺ + CO₃²⁻ → FeCO₃ (protective above ~60°C)
De Waard-Milliams Correlation (simplified):
log₁₀(CR) = 5.8 − 1710/T + 0.67×log₁₀(pCO₂)
Where: CR in mm/year, T in Kelvin, pCO₂ in bar
Typical uninhibited rates:
pCO₂ = 0.5 bar, 60°C: 2–8 mm/year (80–300 mpy)
Sour Corrosion (H₂S)
Hydrogen sulfide causes both corrosion and cracking. The cracking mechanisms (SSC, HIC, SOHIC) are often more critical than metal loss.
H₂S Corrosion & Cracking:
Direct corrosion: Fe + H₂S → FeS + 2H⁰ (atomic)
2H⁰ → H₂ (or diffuses into steel)
Cracking mechanisms:
• SSC: Sulfide stress cracking (high-strength steels, HRC > 22)
• HIC: Hydrogen-induced cracking (blistering, stepwise)
• SOHIC: Stress-oriented HIC (through-wall cracking)
NACE MR0175/ISO 15156 Requirements:
• Carbon steel hardness: ≤ 22 HRC (248 HBW)
• Weld hardness: ≤ 250 HV₁₀
• Post-weld heat treatment per material group
Oxygen Corrosion
Dissolved oxygen dramatically accelerates corrosion—rates 10–100× higher than CO₂ alone. Even ppm-level O₂ ingress is problematic.
Oxygen Corrosion:
Cathodic: O₂ + 2H₂O + 4e⁻ → 4OH⁻
Typical rates with O₂ present:
• Stagnant: 5–20 mpy
• Flowing (5 ft/s): 50–200 mpy
• High velocity (>15 ft/s): 500+ mpy (erosion-corrosion)
Control targets:
• Injection water: < 10 ppb dissolved O₂
• Deaeration: Vacuum tower or nitrogen stripping
• Scavengers: Sodium sulfite (8 ppm per 1 ppm O₂)
Microbiologically Influenced Corrosion (MIC)
Bacterial activity creates localized aggressive environments. MIC causes severe pitting, often 10–100× general corrosion rates.
- SRB (Sulfate-reducing bacteria): Convert SO₄²⁻ to H₂S under biofilms
- APB (Acid-producing bacteria): Generate organic acids, drop local pH to 2–3
- IOB (Iron-oxidizing bacteria): Form tubercles, create differential aeration cells
Corrosion Rate Comparison
| Mechanism | Typical Rate | Key Factor | Primary Mitigation |
|---|---|---|---|
| Sweet (CO₂) | 10–200 mpy | pCO₂, temperature | Film-forming inhibitors |
| Sour (H₂S) | 5–50 mpy + cracking | pH₂S, pH, hardness | Material selection (MR0175) |
| Oxygen | 50–500 mpy | Dissolved O₂, velocity | Deaeration, scavengers |
| MIC | 10–100 mpy (pitting) | Bacterial population | Biocides, pigging |
3. Rate Calculations
Weight Loss Method (ASTM G1-03)
The weight loss method using corrosion coupons remains the industry standard for field corrosion monitoring. Results represent time-averaged corrosion over the exposure period.
ASTM G1 Corrosion Rate Formula:
CR = (K × W) / (A × T × D)
Where:
CR = Corrosion rate
K = Constant (depends on units desired)
W = Weight loss (grams)
A = Exposed surface area (cm²)
T = Exposure time (hours)
D = Material density (g/cm³)
Constants for different units:
K = 3.45 × 10⁶ → CR in mpy (mils per year)
K = 8.76 × 10⁴ → CR in mm/year
K = 8.76 × 10⁷ → CR in μm/year
For carbon steel (D = 7.85 g/cm³):
CR (mpy) = 4.39 × 10⁵ × W / (A × T)
Example: Weight Loss Calculation
Given:
Initial weight: W₁ = 48.526 g
Final weight: W₂ = 48.284 g
Surface area: A = 24.2 cm²
Exposure time: T = 90 days = 2,160 hours
Material: Carbon steel (D = 7.85 g/cm³)
Solution:
Weight loss: W = 48.526 − 48.284 = 0.242 g
CR = (3.45 × 10⁶ × 0.242) / (24.2 × 2,160 × 7.85)
CR = 834,900 / 410,443
CR = 2.03 mpy
Result: 2.0 mpy — Low severity, acceptable rate
Electrochemical Method (ASTM G102-89)
Linear Polarization Resistance (LPR) and Tafel extrapolation provide instantaneous corrosion rate data, enabling real-time monitoring and rapid inhibitor optimization.
ASTM G102 Corrosion Rate Formula:
CR (mpy) = 0.1288 × EW × i_corr / ρ
Where:
EW = Equivalent weight (g/equivalent)
i_corr = Corrosion current density (μA/cm²)
ρ = Density (g/cm³)
From LPR measurement:
i_corr = B / Rp
Where:
Rp = Polarization resistance (ohm·cm²)
B = Stern-Geary coefficient (mV)
B = (βa × βc) / [2.303 × (βa + βc)]
Typical B for steel in CO₂: 13–26 mV
Example:
Rp = 1,000 ohm·cm², B = 26 mV
i_corr = 26 / 1,000 = 0.026 mA/cm² = 26 μA/cm²
For carbon steel (EW = 27.92, ρ = 7.85):
CR = 0.1288 × 27.92 × 26 / 7.85 = 11.9 mpy
Thickness Measurement Method (API 570)
Corrosion Rate from UT Inspection:
CR (mpy) = (t_original − t_measured) × 1000 / years
Example:
Original wall: 0.375 in = 375 mils
Measured wall: 0.358 in = 358 mils
Service time: 12 years
CR = (375 − 358) / 12 = 1.42 mpy
Remaining Life:
Min required thickness: t_min = 0.300 in (for MAWP)
Remaining allowance: 358 − 300 = 58 mils
Remaining life: 58 / 1.42 = 40.8 years
Severity Classification
| Rate (mpy) | Classification | Recommended Action |
|---|---|---|
| < 1 | Negligible | Continue routine monitoring |
| 1–5 | Low | Standard inspection intervals |
| 5–10 | Moderate | Increase monitoring, review inhibitor |
| 10–20 | High | Optimize inhibitor, shorten inspection interval |
| 20–50 | Severe | Immediate action: aggressive inhibition or upgrade |
| > 50 | Critical | Consider shutdown, replacement required |
Pitting Factor
Pitting Factor Calculation:
PF = Maximum pit depth / Average metal loss
Interpretation:
PF < 2: Predominantly uniform corrosion
PF 2–5: Moderate localized attack
PF > 5: Severe pitting — reduce inspection interval
API 570 Adjustment:
When PF > 2, use pitting rate (not general rate) for
remaining life calculations at pitting locations.
API 570 Inspection Interval
Inspection Interval Calculation:
Interval = (t_current − t_minimum) / (2 × CR)
Or equivalently:
Interval = Remaining Life / 2
API 570 Limits:
• Maximum interval: 10 years
• Minimum interval: Based on risk (typically 5 years for critical)
• Safety factor of 2 built into formula
Example:
t_current = 0.365 in (365 mils)
t_minimum = 0.300 in (300 mils)
CR = 3.5 mpy
Interval = (365 − 300) / (2 × 3.5) = 65 / 7 = 9.3 years
→ Use 9 years or 10-year maximum
4. Standards & Testing
Key Industry Standards
| Standard | Title | Application |
|---|---|---|
| ASTM G1-03 | Preparing, Cleaning, Evaluating Corrosion Test Specimens | Weight loss coupon procedure |
| ASTM G102-89 | Calculation of Corrosion Rates from Electrochemical Measurements | LPR, Tafel, EIS rate calculations |
| NACE SP0775 | Preparation, Installation, Analysis of Corrosion Coupons | Field coupon program design |
| NACE MR0175 | Materials for H₂S Environments (= ISO 15156) | Sour service material selection |
| API 570 | Piping Inspection Code | Inspection intervals, remaining life |
| API 580/581 | Risk-Based Inspection | Inspection prioritization |
| NACE TM0177 | SSC Testing Methods | Sulfide stress cracking evaluation |
| NACE TM0284 | HIC Testing | Hydrogen-induced cracking evaluation |
Corrosion Coupon Program (NACE SP0775)
Coupon Specifications:
• Material: Match pipeline metallurgy exactly
• Size: Typically 3" × 0.5" × 0.125" (~24 cm² area)
• Surface: 120-grit finish (reproducible starting point)
• Exposure: 30–90 days typical (longer for low rates)
Installation Requirements:
• Minimum 3 coupons per location (statistical validity)
• Position at pipe bottom (water accumulation)
• Downstream of chemical injection points
• Access fittings per NACE SP0775 specifications
Acceptance Criteria:
< 5 mpy: Acceptable for carbon steel
5–10 mpy: Marginal — increase monitoring
> 10 mpy: Unacceptable — increase inhibitor dosage
Monitoring Methods Comparison
| Method | Response Time | Measures | Limitations |
|---|---|---|---|
| Weight loss coupons | 30–90 days | Average rate, pitting | No real-time data |
| ER probes | Hours to days | Metal loss (cumulative) | No instantaneous rate |
| LPR probes | Minutes | Instantaneous rate | General corrosion only |
| UT thickness | Periodic surveys | Actual wall loss | Point measurements |
| ILI (smart pig) | 5–7 year intervals | Full pipe mapping | High cost, piggable lines only |
5. Mitigation Strategies
Corrosion Inhibitors
Film-forming inhibitors are the primary internal corrosion control method for carbon steel pipelines. Selection depends on fluid composition and operating conditions.
| Inhibitor Type | Mechanism | Application | Typical Dose |
|---|---|---|---|
| Imidazolines | Hydrophobic film on metal | Oil/gas, sweet & sour | 25–100 ppm |
| Film-forming amines | Persistent barrier film | Gas pipelines, dry systems | 10–50 ppm |
| Quaternary ammonium | Cationic surfactant | Water systems | 50–200 ppm |
| Phosphate esters | Reacts to form phosphate layer | Water treatment | 5–20 ppm |
Inhibitor Dosage Calculation
Continuous Injection Rate:
Q_inh (gal/day) = (C × Q_water × 0.000351) / f
Where:
C = Target concentration (ppm)
Q_water = Water rate (bbl/day)
f = Inhibitor active fraction (e.g., 0.50 for 50% active)
0.000351 = unit conversion factor
Example:
Target: 50 ppm
Water: 10,000 bbl/day
Inhibitor: 50% active
Q = (50 × 10,000 × 0.000351) / 0.50
Q = 175.5 / 0.50 = 351 gal/day = 14.6 gal/hr
Inhibitor Efficiency (NACE TM0374)
Inhibitor Efficiency:
IE (%) = [(CR_blank − CR_inhibited) / CR_blank] × 100
Performance Rating:
IE > 95%: Excellent
IE 90–95%: Very good
IE 80–90%: Good
IE 60–80%: Marginal — increase dose or change product
IE < 60%: Poor — change inhibitor chemistry
Example:
Uninhibited rate: 125 mpy (blank coupon)
Inhibited rate: 6 mpy
IE = [(125 − 6) / 125] × 100 = 95.2% — Excellent
Material Selection Guide
| Material | Environment | Expected CR | Relative Cost |
|---|---|---|---|
| Carbon steel + inhibitor | Mild CO₂, inhibited | < 5 mpy | 1.0× |
| 13Cr (Type 410/420) | CO₂, mild H₂S | < 0.5 mpy | 3.0× |
| Duplex 2205 | CO₂ + chlorides | < 0.1 mpy | 4.5× |
| Super Duplex 2507 | Severe sour + Cl⁻ | < 0.01 mpy | 6.0× |
| Alloy 625/C-276 | Extreme sour, high temp | Immune | 12× |
Economic Decision: Compare life-cycle costs: (1) carbon steel + inhibitor program + increased inspection vs. (2) CRA capital cost + reduced operating costs. Breakeven typically 15–30 years depending on corrosivity and inhibitor costs.
Cathodic Protection (External)
NACE SP0169 Protection Criteria:
1. −850 mV vs Cu/CuSO₄ (instant-off potential)
2. 100 mV polarization from native potential
3. −850 mV with IR drop (where native > −800 mV)
Current Requirement:
I (mA) = A_bare × i_density
Typical current densities (μA/ft²):
• Well-coated pipe: 50–200
• Degraded coating: 500–2,000
• Bare pipe: 5,000–20,000
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