Pipelines are widely used in the oil and gas industry for various purposes, such as gathering and transporting fluids from individual wells to a centralized gathering system, delivering products to plants or refineries, transporting gas from processing plants to LNG, LPG, and/or other facilities, distributing final products from plants or refineries to distribution centers, transporting disposal water to injection wells, and delivering other products, such as CO2 and slurry, to the facilities for other uses. According to U.S. Pipeline & Hazardous Materials Safety Administration (PHMSA), the millage of the energy transportation network in the United States is over 2.5 million miles.
The pipeline system can be classified into three categories based on their place in the process between the production site (wellhead) and the final delivery point of the products, including gathering pipeline systems, transmission pipeline systems, and distribution pipeline systems or refined products pipeline systems. The gathering pipeline systems gather fluids streams from individual wells and transport them to a centralized gathering station. The transmission pipeline systems are mainly used to transport natural gas and crude oil from their respective gathering systems to plants and refineries for further processing or storage. Transmission pipelines can be operated at low or high pressures and tens to thousands of miles in length. The pipe size is normally larger than gathering pipelines and thus has a higher throughput capacity. Distribution pipelines deliver natural gas to commercial and residential end-users, the size of which are normally smaller than gas transmission pipelines, while the refined products pipeline systems transport refined products, such as gasoline, kerosene, and other petrochemicals, from refineries to the end-user or to storage. Based on the latest data from PHMSA, the hazardous liquid pipeline network within the United States is over 224,000 miles as of 2019, while the gas distribution pipeline is over 1,328,000 miles and the gas gathering pipeline is over 319,000 miles as of 2020.
Pipeline materials can be classified broadly into ferrous, nonferrous, and plastic pipes. Ferrous material mainly includes carbon steel, stainless steel, and cast iron, while carbon steel is the most commonly used material for processing pipelines. Most gathering and transmission pipelines are constructed of steel, because of its high strength, wide availability, and a large array of connection possibilities. However, it does not handle corrosive environmental conditions as well as stainless steel. Stainless steel can be selected when the environment is very corrosive, such as heat exchangers and boilers. Cast iron is not often used for pressure piping applications because it is brittle. It is mainly sued for drain, waste, and vent application. Nonferrous metal, such as copper, brass, titanium, and aluminum pipes, are selected when particular feathers are wanted, such as their corrosive resistance, good heat transfer, or tensile strength at high-temperature conditions. However, these materials are relatively expensive than steel.
The application of plastic pipe has arisen rapidly since 1950, because it resists corrosion, alleviates the problems caused by wax and/or scale deposition, and reduces friction energy losses due to its smoother surface than steel pipes. According to the latest data from PHMSA, a small portion of gas transmission pipelines are made of plastic pipe, while a large portion of gas distribution pipelines is constructed of plastic pipe. As of 2014, there is approximately 54.5% percent of the main gas distribution pipelines in the United States are made of plastic, while 43% are made of steel pipes; and there is around 70.6% of service gas pipelines are made of plastic compared to 25.85% made of steel pipes. However, it is worth mentioning that the plastic pipe may rupture and fail if subjected to heat or flame impingement. Some typical types of plastic pipe materials are polyvinyl chloride (PVC), chlorinated polyvinyl chloride (CPVC), polyethylene (PE), polypropylene (PP), and reinforced thermosetting resin pipe (RTRP) (or fiberglass reinforced plastic (FRP)).
Pipeline failure causes and prevention
Based on PHMSA, the main causes of pipeline failure are:
- Internal corrosion
- External corrosion
- Stress corrosion cracking (SCC)
- Selective seam corrosion (SSC)
- Excavation damage
- Natural force damage
- Other outside force damage
- Material/weld failure
- Equipment failure
- Incorrect operation
Corrosion refers to the gradual destruction of steel pipe material by chemical or electrochemical reactions with immediate surroundings. Over time, corrosion can lead to reduced strength and increase the risks of pipeline rupture and failure. The data from 1998 – 2017 shows that approximately 18% of pipeline incidents on average were caused by corrosion according to PHMSA. Corrosion can occur at the interior surface of a steel pipe, called internal corrosion, due to the chemical or electrochemical reaction with transporting fluids, and also at the exterior surface, called external corrosion, due to the electrochemical interactions between the pipeline and the soil, air, or water surrounding it. Other types of corrosion can be stress corrosion cracking (SCC), microbiologically-influenced corrosion (MIC), stray current interference corrosion, selective seam corrosion (SSC). Corrosion can grow and worsen with time if left untreated. Therefore, early detection and mitigation are important to minimize the impact of corrosion. It mainly occurs in transmission and gathering pipelines where steel pipes are widely used. The pictures below show examples of internal corroded pipelines.
Corrosion can be prevented by various technologies. The manufacturing process of pipes and their coating must be subject to rigorous fabrication, inspection, and quality control to minimize the occurrence of defects that may lead to corrosion-related failures. Corrosion-resistant material needs to be considered in high corrosive environments. Besides, protective coating, cathodic protection systems, corrosion inhibitor additives, and line cleaning to remove water and other contaminants, are necessary to minimize the impact of corrosion. The quality of the product needs to be carefully controlled. Periodic inspections, testing, assessment, and timely repair or replacement are required to monitor, detect, and avoid any existing or potential damage by corrosion.
Excavation is another major cause of pipeline failure, which makes approximately 15% of incidents for hazardous liquid pipelines and 18% for natural gas transmission pipelines for the period of 2002 through 2003 based on PHMSA’s Office of Pipeline Safety (OPS) reports. Excavation can lead to immediate damage to the pipeline. It can also cause delayed failure because of the damage to the pipeline coating, dents, or scrapes, which can promote corrosion and lead to catastrophic pipeline failure in the future.
Pipeline failure can also be induced by natural forces, such as earthquakes, landslides, subsidence, heavy rains and flooding, high winds, tornadoes, hurricanes, temperature extremes, and lightning. Although the number of failures caused by natural forces is small based on previous data, most of them are catastrophic if it does occur. Other outside force damage can be caused by accidents or fires from other nearby businesses or industries, vandalism, sabotage, or terrorism. Material failure may occur in the steel pipes manufactured in earlier days, which has some impurities that can result in failure. This type of failure accounts for a small percentage of all pipeline failures and can be reduced by the improvement of the steel and pipe manufacturing processes and the welding processes. Besides, to reduce the failure from incorrect operations from humans, operators are required to develop qualification programs for both liquid and gas transmission pipelines for individuals performing certain safety-sensitive functions. Improved work training is also required for operators to enhance their knowledge and expertise.
Pipeline operators are required to periodically perform “integrity assessment” to determine if the pipelines have adequate strength to prevent any leaks or ruptures under normal operation and upset conditions. Some typical inspection methods are in-line inspection (ILI), hydrostatic pressure testing, direct assessment (DA), and close interval surveys (CIS). ILI tools can travel through the pipeline, measure and record irregularities that may indicate corrosion, cracks, laminations, dents, gouges, or other defects. It is also known as “smart pigs”. The operation of a “smart pig” is similar to a conventional pig used to clean pipelines. There are several different types of ILI technologies, such as magnetic ultrasonic tools, ultrasonic tools, and geometry tools. A smart pig can consist of multiple tools with different functions to obtain confidence in inspection results. Flux Leakage (MFL) tool and Transverse MFL/Transverse Flux Inspection tool (TFI) are the two commonly used tools for inspection of hazardous liquid pipelines. These tools measure metal loss, which can be caused by corrosion or gouges, through either a temporarily applied magnetic field or a temporarily applied magnetic field wrapping around the circumference of the pipe. The below pictures show an ILI tool and the signal from MFL that shows metal loss for a liquid pipeline. The two commonly used ultrasonic tools are Compression Wave Ultrasonic Testing (UT) tools and Shear Wave Ultrasonic Testing (C-UT) tools. UT tools can measure pipe wall thickness and metal loss, but requires the pipeline to be cleaned in advance. C-UT is the nondestructive examination technique that can detect longitudinal cracks, weld defects, and crack-like defects. Geometry tools measure the bore of pipe using mechanical arms or electro-mechanical means to identify dents, deformations, and other ovality changes.
Hydrostatic pressure test is normally used to test pipeline integrity immediately after construction and before placing the pipeline in service. It is also performed during the pipeline’s operating life, especially when ILI tools cannot be used. According to PHMSA, during the pressure tests, the pipeline is pressurized by a testing medium (water or gas) using pumps or compressors to at least 125% of the maximum operating pressure (MOP) for at least 4 continuous hours, and another 4 hours at a pressure of at least 110% of MOP if the piping is not visible. If any leakage is identified, pressure tests are repeated after the repair of the leak. Spike tests are required if there is a concern with latent cracks that might grow due to pressure reversal (or flow reversal), product changes, or conversions to service.
Some pipeline systems cannot use ILI tools and/or pressure tests, such as the natural gas pipelines that have poor coupling between the tool and the pipe wall and the pipeline diameters are not unique. In addition, the hydrostatic pressure test using water is not preferred either because of dewatering concerns or interruptions of services to customers. For these cases, DA is necessary. DA can also be combined with other primary methods, such as ILI tools or hydrostatic pressure testing at locations where high risk is suspected. CIS, which is also known as pipe-to-soil and potential gradient surveys, is a method to access the effectiveness of cathodic protection (CP) systems for buried pipelines, which is used for External Corrosion Direct Assessment (ECDA).
Pipeline flow reversal, product changes, and conversion to service
Pipelines may experience flow reversal, production changes (such as crude oil to refined product), conversion to service (such as conversion from natural gas to crude oil), and/or change of throughput capacity depending on the market needs. This can induce changes of pressure gradient, velocity, and location, magnitude and frequency of pressure surges and cycles, liquid accumulation spots, etc. Therefore, the areas of risk may also shift. These changes may also induce significant addition, removal, or modification of existing facilities, such as pump and compressor stations, tank farms, ILI launching and receiving facilities, etc. In 2014, PHMSA provided some guidance to operators for these changes that may impact pipeline integrity1.
In general, the operators need to make sure that the pipelines are in satisfactory conditions for safe operation under the changed conditions prior to the changes. Inspections, such as hydrostatic pressure tests including spike tests, are required, and all known unsafe defects and conditions should be corrected before changes occur. For product changes, it is essential to make sure that the fluid to be transported is chemically compatible with the pipelines, including all the components, and any other commodity that it may come into contact with while in the pipeline.
- PHMSA guidance for pipeline flow reversals, product changes, and conversion to service: https://www.pipelinelaw.com/wp-content/uploads/sites/24/2014/09/Guidance_for_Pipeline_Flow_Reversals_Product_Changes_and_Conversion_to_Service.pdf