It’s been well documented that internal corrosion in gas, liquid and multiphase transmission pipelines is a significant problem that has caused extensive damage to pipelines and operating facilities.
The incidents caused by this problem has led to regulations such as 49 CFR 192 (Sub. O) 2, which states the threat of internal corrosion in a natural gas pipeline system is assumed to exist until an operator can demonstrate otherwise, either through direct assessment, hydrostatic pressure test, in-line inspection or some other technology. This has led to a substantial acceptance of new direct assessment and pipeline integrity focused work by the industry.
The National Association of Corrosion Engineers (NACE), for example, has ratified Internal Corrosion Direct Assessment (ICDA) methods for dry gas, wet gas and liquid product pipelines to meet the need for pipeline integrity with respect to likelihood of internal corrosion. ICDA is designed to prioritize the likelihood of corrosion along a pipeline and identify locations most susceptible to internal corrosion damage. These prioritized critical locations are then excavated and examined, and results of these inspections are used as the basis for assessing the integrity of the complete pipeline. In effect, inspection data from a select few locations along the pipeline is used to characterize integrity of the entire pipeline. Performing successful ICDA applications relies heavily on the ability to model flow and accurately quantify/predict corrosion damage along the pipeline.
Although it’s necessary, the presence of aqueous electrolyte-like water or a conductive medium alone is not a sufficient condition for internal corrosion damage to occur in wet gas or dry gas pipelines. Other operating characteristics of the pipeline, such as in-situ pH, acid gas content, pressure and temperature also have a significant impact on the magnitude of corrosion. Even though the presence of liquid water provides a necessary medium for corrosion to occur, the actual parametric conditions, flow dynamics and composition of the transmitted gas affect the extent of corrosion.
Direct Assessment (DA) consists of three areas: External Corrosion Direct Assessment (ECDA), Internal Corrosion Direct Assessment (ICDA) and Stress Corrosion Direct Assessment (SCCDA). All three DA methodologies are aimed at improving pipeline safety proactively by assessing the risk and reducing the impact of the corrosion threat being addressed. These are designed to be cost-effective integrity management tools that complement detailed inspections such as in-line inspection (ILI) and hydrostatic test.
ICDA has been further classified into three areas: Dry Gas ICDA 3, Wet Gas ICDA 4 and Liquid Petroleum ICDA. Multiphase ICDA is currently in the works and focuses on onshore and offshore pipelines that carry multiphase fluids.
These methodologies use a four-step continuous improvement process detailed as follows:
Pre-Assessment: Focuses on collecting historic and current operating data about the pipeline, which determines feasibility of application and defines ICDA regions for further analyses.
Indirect Inspection: Includes the use of appropriate modeling tools and techniques for prediction and prioritization of overall corrosion severity at different locations (assessment sites) along a pipeline segment to undergo detailed examination.
Direct Examination: Includes performing actions for detailed examination of assessment sites prioritized to have the highest corrosion severity identified in the Indirect Inspection step. Detailed examination of the internal surface of a pipe involves nondestructive examination (NDE) methods sufficient to identify and characterize corrosion rates and wall losses.
Post-Assessment: Covers analyses of data collected from the previous three steps to assess the effectiveness of the ICDA process, determine reassessment intervals and establish corrosion control strategies.
The successful application of each of these steps relies heavily on the proper application of the preceding step with a focus on collecting all relevant data and operating history in the Pre-Assessment step and using the right tools and technology in the Indirect Inspection step.
The primary assumption of most gas pipeline operators is that internal corrosion does not exist in their pipelines. This is a difficult contention to corroborate without a detailed assessment and evaluation. On the contrary, internal corrosion is very likely to exist in measurable quantities where there is a presence of liquid water and acid gases.
Furthermore, the actual areas that are affected by corrosion in dry gas pipelines are small compared to the lengths of pipeline transporting gas, making it difficult to locate and mitigate corrosion. Using ICDA techniques provides the operator with tools to focus inspection resources where they are needed and help make integrity assessments on the entire pipeline.
ICDA relies on identifying most susceptible locations along the pipeline and inspecting these locations. Dry Gas ICDA (DG-ICDA) prioritizes inspection sites based on the likelihood of water accumulation whereas Wet Gas ICDA (WG-ICDA) prioritizes inspection sites based on water holdup and predicted corrosion rates. Based on the inspection results of these inspection sites, the integrity of remaining pipeline is assessed.
Operating parameters such as gas flow rate, pressure, temperature and pipe ID are used to calculate the critical angle requirements for DG-ICDA. The selection of the most representative operational conditions for DG-ICDA modeling is critical because typically pipeline operating conditions are dynamic and change with seasonal variations and load requirements.
WG-ICDA relies heavily on the ability of the internal corrosion prediction model (ICPM) to accurately predict corrosion rates as a function of flow rate, acid gas composition, water composition, in-situ pH, scale protection and water hold-up. The ability to classify sub-regimes based on changes in flow regime is a critical aspect of facilitating a successful WG-ICDA program.
Using an ICPM that provides the ability to evaluate both the flow dynamics of the pipeline to calculate flow regimes and liquid holdup along with an accurate corrosion prediction simplifies the process and enhances the accuracy of identifying locations that can be prioritized for inspection.
The incremental value of correctly characterizing the flow simulation significantly outweighs the value of high-precision electronic elevation modeling or GPS surveys5. The selection of an advanced flow and corrosion prediction model forms a key component in the completion of a successful ICDA program.
The ideal solution for corrosion prediction and monitoring DG-ICDA has been widely implemented across the gas pipeline network in the Americas by many pipeline operators. There have been mixed reports regarding the success and value of these programs. According to some, the process has been found to be highly effective for evaluating pipeline integrity with respect to the internal corrosion threat5. The overall effort required to implement DG-ICDA is not significantly more or less than any other integrity assessment processes. However, WG-ICDA was ratified only two years ago and reports about its implementation and experience are not readily available in the industry. ICDA provides a robust framework for performing cost-effective integrity assessments, and advanced technology based flow and corrosion models vastly enhance this process to ensure the area of corrosion is found without unnecessary digging or random inspection.
The ideal solution should incorporate four broad technologies: multiphase flow modeling, corrosion prediction, use of current ICDA methodology and real-time corrosion monitoring. These types of technologies are capable of not only determining propensity for water retention, but also the “corrosivity” of the environment in the presence of the aqueous medium for the identified critical segment.
This type of system integrates a number of key functionalities, including water-phase behavior determination, pH computation, corrosion modeling, flow modeling and comprehensive pipeline analyses based on lab and field data. A screenshot of a typical result view identifying the critical areas is shown in Figure 3.
Real-time corrosion measurement technology can collect corrosion rate data every minute, and save the data on the device where it will be available for retrieval during operator rounds. If available, this corrosion data could be routed through existing wireless or radio communications as well. Locating the corrosion monitors at key points along a wet gas pipeline can provide continuous reliability information to the operator.
The technology described in this paper provides a rigorous framework to identifying critical inclination segments in a pipeline that may be affected by internal corrosion, and provide a rationale for implementing a real-time monitoring-based methodology to inspect, monitor and provide remediation as needed. The methodology of the ICDA, powered with advanced flow and corrosion prediction models and best-in-class monitoring solutions provides three significant and concrete benefits to pipeline operators:
(a) Ability to perform characterization of pipelines in terms of potential for corrosion damage and determination of critical locations /pipeline segments that require physical inspection with the use of advanced flow and corrosion prediction models
(b) Ability to assess the health of the entire pipeline by performing inspections on selected critical areas of the pipeline in line with existing NACE standards
(c) Ability to view and assess the status of the critical areas in real-time with the application of monitoring technology coupled with real-time data processing
The use of the ICDA framework, empowered with advanced flow models and corrosion prediction tools, encapsulates industry leading technology and proven modeling and monitoring systems. It provides pipeline operators compelling cost and safety benefits, such as the ability to easily identify critical areas, proactively prevent corrosion failures and develop efficient, knowledge-based inspection programs for pipeline condition assessment, and monitoring potential for internal corrosion damage in these critical segments through real-time monitoring.
1) Pipeline and Hazardous Materials Safety Administration (PHMSA) – Significant Incidents Files, June 2012
2) U.S. Code of Federal Regulations (CFR) Title 49. “Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards.” Part 192.
3) NACE SP0206, “Internal Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Natural Gas (DG-ICDA)”
4) NACE SP0206, “Internal Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Natural Gas (DG-ICDA)”
5) “Improving the success of DG-ICDA Projects”, S.F. Biagiotti, J. Fox, NACE Paper 08128, Corrosion 2008