Why Uniform Corrosion Is Often Less Dangerous Than Localized Corrosion
This approach overlooks a critical reality: uniform corrosion is often far less dangerous than localized corrosion, even when average corrosion rates appear low. Most catastrophic pipeline failures are driven by localized damage mechanisms that escape conventional corrosion indicators.
This article explains why localized corrosion represents a much higher integrity threat than uniform corrosion and how integrity management must adapt accordingly.
How Often Should a Pipeline Integrity Review Really Be Performed?
In practice, some high-risk pipelines require more frequent reviews, while stable systems may not benefit from rigid calendar-driven cycles. The real question is not “How often?” but “Under which conditions should an integrity review be performed?”
This article explains how integrity review frequency should be determined and why a risk-based approach is essential.
Why Corrosion Rates Are Often Underestimated During Early Field Life
Many corrosion-related failures originate from mechanisms initiated during early field life but detected much later. This article explains why corrosion rates are frequently underestimated during early operation and how this underestimation compromises long-term pipeline integrity.
What Makes a Pipeline Fit for Continued Operation?
Determining whether a pipeline is fit for continued operation is one of the most critical decisions in pipeline integrity management. Yet, this decision is often oversimplified and reduced to a single question: “Is the remaining wall thickness acceptable?”
Fitness for continued operation is not a thickness criterion. It is a multidimensional engineering judgment that integrates defect characteristics, degradation mechanisms, operating conditions, and risk tolerance.
This article explains what truly makes a pipeline fit (or unfit) for continued operation, and why relying on isolated inspection metrics leads to unsafe decisions.
How Corrosion Mechanisms Evolve Over the Life of a Pipeline
Industry experience shows that most recurring corrosion failures are not caused by unknown mechanisms, but by incorrectly identified ones. This article explains how internal corrosion mechanisms should be identified in pipelines and why this identification is fundamental to sound integrity decisions.
Why Corrosion Rates Are Often Underestimated During Early Field Life
Industry experience shows many corrosion-related failures originate from mechanisms initiated during early field life but detected much later. This article explains why corrosion rates are frequently underestimated during early operation and how this underestimation compromises long-term pipeline integrity.
How to Define Pipeline System Limits in an Integrated Upstream–Downstream Environment
Defining pipeline system limits is one of the most underestimated steps in pipeline integrity management. In integrated upstream–downstream environments, pipelines rarely operate as isolated assets. They are connected to wells, processing facilities, platforms, storage systems, and utilities, often managed by different teams or even different entities.
Poorly defined system limits are a recurring root cause of integrity gaps, missed inspection scopes, unclear responsibilities, and inconsistent operating practices. This article explains how pipeline system limits should be defined and why this definition is fundamental to effective integrity management.
How Gas Condensation Leads to Unexpected Internal Corrosion
This article explains how gas condensation occurs in pipelines, why it leads to aggressive internal corrosion, and how integrity management programs often fail to anticipate this mechanism.
Why Pipeline Integrity Cannot Be Managed Only Through ILI and Leak Detection
In-line inspection (ILI) tools and leak detection systems are often perceived as the backbone of pipeline integrity management. Many operators assume that as long as pipelines are regularly inspected and equipped with leak detection, integrity risks are adequately controlled.
Industry experience shows the opposite: a significant number of pipeline failures occur in systems that were inspected and monitored. The issue is not the lack of technology, but the misconception that inspection and detection alone are sufficient to manage integrity.
This article explains why pipeline integrity cannot be reduced to ILI and leak detection, and why integrity management must be approached as a broader, risk-based process.
How Temperature Influences CO₂ Corrosion in Unexpected Ways
This article explains how temperature influences CO₂ corrosion in sometimes counterintuitive ways, and why integrity engineers must treat temperature as a regime-shaping parameter, not a simple multiplier.
Why CO₂ Corrosion Often Concentrates at the 6 o’clock Position in Pipelines
This article explains why CO₂ corrosion preferentially develops at the 6 o’clock position and why this localization is often underestimated in integrity assessments.
When Iron Carbonate (FeCO₃) Becomes Protective… and When It Does Not
This article explains when iron carbonate becomes protective, when it does not, and why integrity assessments frequently overestimate its effectiveness.
Why CO₂ Partial Pressure Is the Key Parameter for Corrosion Assessment in Carbon Steel Pipelines
This article explains why CO₂ partial pressure is the governing parameter for CO₂ corrosion and how it should be correctly used in integrity and maintenance decision-making.
Sacrificial Anodes vs Impressed Current: How to Choose the Right Cathodic Protection System
This article explains how integrity engineers should choose between sacrificial anodes and impressed current systems, based on asset characteristics, operating environment, and lifecycle considerations.
How CO₂ Causes Corrosion in Carbon Steel Pipelines
CO₂ corrosion, often referred to as sweet corrosion, is one of the most common internal corrosion mechanisms affecting carbon steel pipelines in the oil and gas industry. Despite being widely studied and relatively well understood, CO₂ corrosion remains a frequent cause of unexpected pipeline degradation and failures.
The root cause is not a lack of knowledge, but a simplified understanding of how CO₂ actually leads to corrosion under real operating conditions. This article explains the fundamental mechanism of CO₂ corrosion in carbon steel pipelines and why its severity is often underestimated in integrity management.
Why Pipelines Only Corrode When Free Water Is Present
One of the most fundamental principles of pipeline corrosion is also one of the most misunderstood: pipelines do not corrode without free water.
This article explains why free water is the true enabler of pipeline corrosion and why managing water is central to pipeline integrity management.
How to Correctly Identify Internal Corrosion Mechanisms in Pipelines
Correct identification of corrosion mechanisms is essential. Treating CO₂ corrosion as MIC, or erosion-corrosion as pure corrosion, leads to ineffective mitigation.
What Does a Pipeline Integrity Management System Really Include Beyond Inspections?
In many organizations, Pipeline Integrity Management Systems (PIMS) are still perceived as a combination of periodic inspections, in-line inspections (ILI), and leak detection systems. While these elements are essential, they represent only a fraction of what an effective PIMS must deliver.