Introduction: The Silent Threat in Pipelines

Internal corrosion is one of the leading threats to pipeline safety, reliability, and operating costs. It is responsible for up to 30% of pipeline failures in oil and gas operations, leading to unplanned downtime, environmental incidents, and regulatory scrutiny. When liquids, water, CO₂, H₂S, or microbes contact the pipe’s inside surface, localized metal loss, under-deposit corrosion, and cracking can develop—often without obvious external signs until failure.

A structured internal pipeline corrosion management program reduces risk, extends asset life, optimizes chemical use, and helps meet regulatory and stakeholder expectations.

1. Key Causes of Internal Corrosion

Internal corrosion arises from a combination of chemical, electrochemical, and biological processes. Major drivers include:

• Water presence and phase changes: Free water or condensate forms corrosive films, accelerating metal loss, highlighting the importance of under-deposit corrosion mitigation.

• Acid gases (CO₂ / H₂S): Create acidic environments, promoting uniform and localized corrosion and sulfide stress cracking in susceptible steels.

• Chlorides, oxygen, and contaminants: Salts and oxygen increase corrosion rates; oxygen is especially aggressive in otherwise anoxic systems.

• Under-deposit and flow-assisted corrosion: Deposits isolate parts of the pipe, creating differential aeration cells and localized attack. Flow-assisted corrosion monitoring is critical here.

• Microbiologically influenced corrosion (MIC): Bacteria such as sulfate-reducing and acid-producing species form biofilms, causing rapid, localized corrosion that is hard to predict. Proper microbiologically influenced corrosion control strategies are essential.

2. Pillars of an Internal Pipeline Corrosion Management Program

A robust program rests on three linked pillars: Threat Assessment, Mitigation, and Monitoring & Verification.

Threat Assessment and Pipeline Integrity Risk Assessment

• Characterize fluid chemistry: water cut, pH, CO₂, H₂S, chlorides, oxygen.

• Map operating regimes: flow, temperature, slugging, pigging frequency.

• Identify high-risk locations: low spots, pig traps, separators, compressor/pump stations.

• Conduct pipeline integrity risk assessment to prioritize inspection and mitigation activities.

Mitigation (Preventive Controls)

• Corrosion inhibitors: Film-forming chemistries, dosed correctly, remain the most widely used mitigation. Selection depends on CO₂/H₂S service and compatibility with upstream processes. Proper pipeline corrosion inhibitor selection ensures effectiveness.

• Operational controls: Reduce free water (dehydration), control oxygen ingress, manage temperature and flow to avoid stagnant zones.

• Physical measures: Internal coatings, filtration/strainers, and pigging programs remove deposits and ensure even inhibitor distribution, supporting under-deposit corrosion mitigation.

• Material selection & design: Use corrosion-resistant alloys or lined sections in high-risk zones for new builds or replacements.

Monitoring & Verification

• Sampling & lab analysis: Regular tests for acidity, microbial content, and chlorides to evaluate inhibitor performance.

• Inline inspection (ILI / pigging): Smart pigs detect metal loss and denting; trending enables growth-rate calculation and re-inspection planning.

• Direct assessment (ICDA / WG-ICDA): AMPP procedures for wet gas systems where ILI isn’t feasible.

• Corrosion coupons and probes: Quantify corrosion rates and verify inhibitor effectiveness.

• Microbiological monitoring: Rapid tests detect MIC early for remedial action. Microbiologically influenced corrosion control is critical in this step.

• Flow-assisted corrosion monitoring ensures active detection of erosive areas.

3. Special Topic: Microbiologically Influenced Corrosion (MIC)

MIC requires focused tactics because microbes colonize deposits, generating aggressive localized attack.

Best practices include:

• Routine microbiological sampling of solids and water; use qPCR-based rapid checks.

• Minimize nutrient sources and remove deposits via pigging and filtration.

• Apply targeted biocide programs (oxidizing or non-oxidizing), validated by monitoring.

• Combine chemical and mechanical controls—chemicals alone rarely succeed without deposit removal and good flow assurance.

4. Choosing and Validating Corrosion Inhibitors

Not all inhibitors perform equally. Selection depends on fluid composition, temperature, and flow.

Steps for selection:

1. Laboratory compatibility testing: Simulate field conditions and evaluate candidate inhibitors for film formation and efficiency.

2. Field trials: Controlled testing with sampling, probes, and coupons ensures effectiveness without adverse effects. Proper pipeline corrosion inhibitor selection ensures long-term protection.

3. Monitor deposit formation & distribution: Ensure inhibitors reach all pipe areas to prevent untreated pockets and localized corrosion.

5. Inspection Frequency & Risk-Based Planning

Inspection intervals should be data-driven rather than arbitrary.

• Use measured corrosion rates and pipeline integrity risk assessment to plan re-inspection.

• Integrate ILI, coupon data, operational logs, and lab results into a corrosion management platform for trend analysis and root-cause identification.

6. Case Study Highlights

• Regular pigging + inhibitor program: Combining smart pigging with controlled inhibitor dosing reduces under-deposit corrosion and maintains low average corrosion rates.

• ICDA for wet gas lines: Provides structured assessment when ILI is impractical.

• Data-driven optimization: Centralized corrosion management systems optimize chemical use while maintaining safety margins.

7. Practical Checklist to Get Started

• Map pipeline sections and identify water/slugging zones.

• Start baseline sampling (chemistry, microbes, solids); install coupons/probes.

• Set up pigging schedules and inspect deposits.

• Run lab inhibitor screening; begin monitored field trials.

• Implement ILI or ICDA plan; integrate results into a corrosion management platform.

• Create KPI dashboards (corrosion trends, inhibitor usage, ILI defects).

• Review materials/design choices for future replacements or lining.

8. Regulations, Standards, and Resources

Operators should align with:

• AMPP/NACE practices

• ASME & API guidance

• Local regulatory requirements for pipeline integrity

• PHMSA and industry technical reports

Conclusion

Investing in a structured internal pipeline corrosion management program pays off through:

• Avoided failures and unplanned downtime

• Optimized chemical spend

• Predictable asset life extension

Start with threat assessment, choose the right mix of chemical and mechanical mitigation, and verify performance with rigorous monitoring. Integrating flow-assisted corrosion monitoring, microbiologically influenced corrosion control, and pipeline corrosion inhibitor selection separates reactive fixes from resilient pipeline operations.