The Source of Shared Knowledge for Pipeline Professionals
View all of our podcasts, white papers, videos and other resources on the subject of Integrity.
Terri Larson covers 6 things she learned about Initial Response during her time working in Marshall, Michigan after a Type 1 incident.
The Accidental PIO: 6 Things a Pipeline Crisis Communicator Learned about Initial Response
API 1133: applies to new and existing hydrocarbon pipelines that transport gas and hazardous liquids. This Recommended Practice is intended to apply to onshore waterways and coastal zones that may be susceptible to hydrotechnical hazards. An onshore waterway is any man-made or natural channel through which water flows. Coastal zones extend offshore to a water depth of 15 ft and extend inland to include those areas of land influenced by tidal action, storm surge, back water flooding, and other coastal hazards.
API 1160: provides a process within a management system framework for operators to assess potential risks and make day-to-day decisions. Through effective integrity management, pipeline operators can significantly reduce the likelihood of an incident and adverse effects on the public, employees, and the environment.
API 1163: overs the use of in-line inspection (ILI) systems for onshore and offshore gas and hazardous liquid pipelines. This includes, but is not limited to, tethered, self-propelled, or free-flowing systems for detecting metal loss, cracks, mechanical damage, pipeline geometries, and pipeline location or mapping, The standard applies to both existing and developing technologies.
API 1176: enhances pipeline integrity by providing a comprehensive guide on how to predict and prevent pipeline failures due to cracking.
API 1178: provides instruction on data integration that supplements other API pipeline integrity documents, specifically API RP 1160, Managing System Integrity for Hazardous Liquid Pipelines for Integrity Management.
API 1179: provides guidelines related to hydrostatic testing as a tool for integrity management in gas and liquids pipelines. This Technical Report specifically focuses on program design and key parameters for consideration in hydrostatic test programs, as well as potential detrimental effects of hydrostatic testing.
ASME B31Q: is the Pipeline Personnel Qualification standard. Find more information on this qualification standard at ASME.org.
Compressor Station: the location where natural gas is compressed to increase its pressure, causing the gas to move through a pipeline. A compressor automation or optimization project addresses the needs of pipeline operators to improve reliability, response time, and data collection in the field.
Computational Pipeline Modeling (CPM): a digital method of mapping out a pipeline’s operational conditions and processes to track the flow of a liquid or gas through the pipeline.
CPM (Computational Pipeline Modeling): a digital method of mapping out a pipeline’s operational conditions and processes to track the flow of a liquid or gas through the pipeline.
Custody Transfer: the physical transfer of natural gas or liquid between operators. Accuracy is vital to ensure the safe and compliant transfer of a substance.
Distribution Pipelines: complete the process of delivering the substance to the desired destination. A Local Distribution Company (LDC) transports natural gas from a main delivery point to consumers through a pipe distribution system.
Gathering Pipelines: form a network of interconnected pipelines to gather a substance such as crude oil or natural gas to send to a treatment or processing facility.
High-Consequence Areas (HCAs): defined by PHMSA as a potential impact zone that contains 20 or more structures intended for human occupancy or an identified site. PHMSA identifies how pipeline operators must identify, prioritize, assess, evaluate, repair, and validate the integrity of gas transmission pipelines that could, in the event of a leak or failure, affect HCAs.
Inline Inspection (ILI): a method to assess the integrity and condition of a pipe by determining the existence of cracks, deformities, or other structural issues that could cause a leak.
Integrity Management: a systematic approach to operate and manage pipelines in a safe manner that complies with PHMSA regulations.
Leak Detection Systems: include external and internal methods. External methods are based on observing external factors within the pipeline to see if any product is released outside the line. Internal methods are based on measuring parameters of the hydraulics of the pipeline such as flow rate, pressure, density, or temperature. The information is placed in a computational algorithm to determine whether there is a leak.
OQ Integrity Process: is the industry program (OQIP) that strives for a universal approach to meet the PHMSA Operator Qualification Expectations, as developed and created by the industry’s OQ Integrity Coalition.
Pigging: the use of devices known as “pigs” to perform maintenance operations. This tool associated with inline pipeline inspection has now become known as a Pipeline Inspection Gauge (PIG).
Pipeline Operators Forum (POF): brings together pipeline inspection and integrity engineers to establish good practices to improve the quality of pipeline integrity management. POF has released specifications and requirements for inline inspection of pipelines through a set of documents.
Pipeline Pigging and Integrity Management Conference (PPIM): devoted exclusively to pigging for maintenance and inspection, as well as pipeline integrity evaluation and repair.
Pipeline Safety Management Systems (PSMS): an industry-wide focus to improve pipeline safety, driving toward zero incidents.
Pump: used in pumping stations to continue moving a substance through the pipeline.
Pumping Station: placed at strategic locations throughout a pipeline to check the pressure, continue moving the substance through the line, monitor the flow of the substance, and communicate the information to a facility.
Real-Time Transient Model (RTTM): simulates the behavior of a pipeline using computational algorithms. The model, which is driven by the field instrumentation, monitors discrepancies between the measured and calculated values potential caused by a leak. RTTM uses flow, pressure, temperature, and density among many other variables.
Telemetry: an automated communications process. During this process, measurements and other data are collected at remote locations and transmitted to receiving equipment for monitoring and data analysis.
Transmission Pipelines: consist of a long series of pipes that move substances across large areas. Compressor stations and pump stations are placed along the pipeline to continue moving the substance through the line.
Preventive and Mitigative (P&M) regulations such as 49 CFR 192.935 for Gas Transmission Pipeline Integrity Management have traditionally focused on physical risks and threats to pipeline assets.
Learn how transmission operators can use Pipeline SMS (PSMS / API 1173) as a method to root out organizational failure as part of their P&M program.
Pipelines are a valuable asset and need to be protected. In order to achieve this, a modern pipeline integrity management program should include regular inspections followed by integrity assessment, and if required repair and rehabilitation measures.
Access this resource from ROSEN to learn more about why pipeline operators need a well-proven method for the inspection of pipelines, especially high-pressure transmission pipelines, through the use of automated inspection tools that can survey pipelines from within.