This paper examines both the method and results of a leak detection sensitivity analysis for a liquid pipeline. A fractional factorial design is used to quantify both primary effects as well as confounding effects between parameters. The analysis examines the impact of uncertainty and bias in pressure and flow measurements, as well as spatial and temporal discretization on leak flow estimation. These are considered under conditions of transient pressures, the presence of a leak and with altered SCADA poll frequency. The results of the parametric study as well as the applicability of the general approach are discussed.
INTRODUCTION AND BACKGROUND
The ability of pipeline operators to swiftly detect pipeline leaks is critical to the safeguarding of public and environmental interests. One of the prevalent tools for achieving this ability within industry is the use of a real time transient model of the pipeline. A primary benefit of utilizing a real time transient model for pipeline leak detection is the ability to accurately represent the pressure profile of the pipeline under transient conditions (Learn, 2015). A more accurate representation of pipeline transients leads to a more accurate estimation of linepack and hence a lower error in the leak flow estimate. As a result, alarm threshold values can be lowered without increasing false alarm frequency, and a better leak detection sensitivity can be achieved.
One of the more challenging roles for a leak detection engineer is to assess and understand the multitude of parameters affecting the error in leak flow estimation. The most widely applied standard, API1149 (1993), provided an excellent theoretical framework for estimating leak flow uncertainty as a function of time averaging window and telemetry uncertainty. However, the most recent update to this standard recognizes that potentially many different parameters affect leak flow uncertainty and recommends a perturbation approach against a reference model. (Salmatanis, 2015)
Given the number of parameters which may affect leak detection sensitivity, a more efficient method is needed to assess the impact of such parameters. Assessing all the potential effects of all parameters within a large quantity of scenarios can be time consuming. It can be onerous to perform this analysis on pipelines in the early stages of project development, during which certain other design assumptions are yet to be confirmed. In addition, many projects may never progress beyond the prospecting stage despite significant design and analysis.
Nicholas, Ed (Nicholas Simulation Services) | Carpenter, Philip (Great Sky River Enterprises LLC) | Henrie , Morgan (MH Consulting, Inc.) | Hung, Daniel (Enbridge Pipelines, Inc.) | Kundert, Kris (Enbridge Pipelines, Inc.)
Testing of pipeline leak detection systems can be challenging. It is also a critical activity which provides key information on the systems capability for communications to regulators and key stakeholders. The authors describe an API RP 1130 compliant test method that relies on the development of a limited number of realistic "leak signatures" that are superimposed on archived SCADA data in a way that preserves not only a faithful representation of the leak, but the real-world impacts of noise, calculation uncertainties, and measurement errors as well. In addition to maintaining high hydraulic fidelity, coverage and flexibility, this procedure is performed at low cost while potentially providing a greater degree of insight into the detailed performance of the leak detection system than can be achieved with other methods.
INTRODUCTION AND BACKGROUND
The Need for Testing of Pipeline Leak Detection Systems
A leak detection system (LDS) is a safety and integrity-critical component of an operating pipeline that is designed to help mitigate negative consequences following an unplanned commodity release. Its intended purpose is to reduce the potential negative impacts from a breach in pipeline hydraulic integrity (e.g., a leak with its resulting spill). Reducing these potential negative impacts is achieved by rapidly detecting the leak and determining its most probable location. Determination of these factors in as short as time frame as possible provides key information that is critical in terms of enabling the pipeline operator to respond faster, more effectively, and with greater precision. Note that the most commonly applied method for leak detection is via Computational Pipeline Monitoring (CPM) systems, which are the explicit focus of this document.
As part of the operator’s overall spill response plan the organization should be able to quantify the leak detection system’s predicted performance. This allows the operator to identify areas where further leak detection improvements are desirable and refine location specific response plans. It also provides a mechanism by which the LDS performance can be monitored and tracked over time.
Quantifying the leak detection performance requires testing. As stated in the American Petroleum Institute recommended practice 1130 (API 1130), “[t]he primary purpose of testing [quantifying] is to assure that the CPM system will alarm if a commodity release occurs.” Note that while API 1130 is specific to Computational Pipeline Monitoring leak detection systems, the quantification of system testing is applicable to all leak detection systems.
In the oil and gas industry, the question “What do you do for a living?” will get you the typical responses: “I’m an engineer.” It is not often that you will hear: “I keep pipelines from blowing up.” In an industry that is constantly developing upstream technologies to meet the global demand for oil and gas, we rarely shine a spotlight on the transportation of these commodities. How the industry ensures “safe” transportation of natural gas and oil from wells to processing plants, storage, and to end users. The industry downturn and the associated oil glut has helped to highlight the world of pipelines and has allowed engineers entering the market to learn more about the growing field of pipeline integrity management.
This paper will discuss and demonstrate technology developed by PG&E and GTS to address the unprecedented increase in safety work occurring at PG&E. The new technology, called Batch Analysis Tool (BAT) enables the planning engineer to analyze systems under a multitude of demand and operating conditions as a “batch” of simulations. User-defined scenarios are performed and cataloged in an automated, sequential manner rather than manually, one run at a time. This approach allows for the performance of hundreds or thousands of scenarios accurately and rapidly. This process also aids in optimizing operations and uncovering non-intuitive solutions. The benefit of this technology extends beyond companies with large amounts of safety work to include any study that requires a range of inputs to be hydraulically analyzed.
The significant benefits Business justification and strategic technology are the primary emphases of this presentation. Representative use cases of the new technology are presented by PG&E in PSIG papers 1614 and 1615.
Introduction and Background
A planning engineer’s job is to perform hydraulic analysis studies of pipeline networks. Hydraulic studies rarely only require 1 or 2 simulation runs to provide a complete study. Instead, a range of runs or scenarios must be performed to provide a sufficiently thorough study. Because of this, planning engineers run many simulations over the course of month, year, or career. Given the large number of runs performed significant benefits can be gained my making the task of performing simulation runs more time efficient. This can not only result in labor savings but also allow for more runs to be performed, increasing the thoroughness and accuracy of the study.
The pace of safety work on PG&E’s gas system has greatly increased the amount of hydraulic analysis and simulation runs required by planning engineers in the Gas System Planning department. Under this pressure of workload PG&E began developing new technology that would allow hundreds to thousands of pipeline simulation runs to be performed automatically as a group or “Batch”. PG&E now uses the Batch Analysis Tool or BAT extensively to meet workload demands, provide more thorough and accurate analysis, and provide critical system intelligence about a gas system operated frequently operating with reduced capacity due to pipeline outages to accommodate safety work.
Overview of PG&E Gas SystemPG&E owns and operates a pipeline network that extends from both the northern California/Oregon and southern California/Arizona borders. This network of 6,750 miles of transmission and 32,000 miles of distribution pipe serves 4.4 million end use gas customers, covering two thirds of California. Pressures range from over 2000 psig on transmission to 7 inches of water column on low pressure distribution systems. Annual sendout is approximately 1 Tcf. Figure 1 provides an overview of the PG&E gas transmission system.
Transmission pipelines that cross regions prone to ground movement events are subject to large longitudinal strains and plastic circumferential elongation as the pipeline experiences alignment changes resulting from differential ground movement. The design trend for new pipelines in areas prone to ground movement has evolved from a stress-based design approach to a strain-based design (SBD) approach to maximize the cost benefits from using higher-strength line pipe steels. This paper presents an overview of SBD for pipelines subjected to large longitudinal strain and high internal pressure, with emphasis on the tensile strain capacity of microalloyed line pipe steel. The technical basis for this paper involved engineering analysis and examination of the mechanical behavior of grade X80 line pipe steel in both the longitudinal and circumferential directions. Elastic-plastic analyses were performed at various internal pressures. SBD models discussed in this paper are based on classical plasticity theory and account for material anisotropy, triaxial strain, and microstructural damage effects developed from test data. The results are intended to enhance SBD and analysis methods for producing safe, cost-effective pipelines capable of accommodating large plastic strains.
Transmission pipelines that cross regions prone to ground movement events can experience large longitudinal strains resulting in circumferential strains due to Poisson's effect. The design trend for new pipelines in areas prone to ground movement has evolved from a stress-based design approach to a strain-based design (SBD) approach to further realize the cost benefits from using higher strength line pipe steels. This paper presents an overview of SBD for pipelines subjected to large cyclic longitudinal strain and high internal pressure, with emphasis on the cyclic tensile strain capacity of microalloyed line pipe steel. The technical basis for this paper involved engineering analysis and examination of the mechanical behavior of grade X80 line pipe steel in both the longitudinal and circumferential directions. Low-cycle fatigue analyses were performed with varying internal pressures. SBD models discussed in this paper are based on classical plasticity theory and account for material anisotropy, triaxial strain, and microstructural damage effects developed from test data. The results are intended to enhance SBD and analysis methods for producing safe, cost-effective pipelines capable of accommodating large plastic cyclic strains.
The American Petroleum Institute (API) publication number 1149 (first published in 1993)  is perhaps the first accepted industry procedure for the numerical assessment of uncertainty in software-based Computational Pipeline Monitoring (CPM) leak detection systems (LDS). This publication remains valid and extremely valuable within its range of applicability. Generally speaking, it is designed for crude oil and refined products pipelines. It also focuses on (while also discussing other ancillary issues) single, straight pipelines and on the Material Balance method of CPM, particularly under steady state conditions.
A recent initiative sanctioned through American Petroleum Institute (API) and sponsored by the Pipeline Research Council International (PRCI) has developed a revision of procedure for the assessment of uncertainty in CPM techniques, in light of a number of recent technological developments and operational requirements. It is also directed at engineering uncertainty factors that prove, in practice, to have a significant effect on LDS uncertainty but that were not thoroughly addressed in the 1993 version.
The new procedure’s aim to follow the standard API and ASME measurement uncertainty practice of defining a Reference Value, a Bias and a Precision for LDS, just as with any other industrial measurement system. In particular, it is possible for the reference conditions of the pipeline to be estimated using a transient pipeline system simulation model – the Reference Model – that takes all the relevant engineering uncertainty factors into account. In this respect, the procedure is similar to a formalized, statistical Leak Sensitivity Study (LSS) as is often performed as part of the requirements analysis and design of a software-based LDS.This paper provides an overview of the procedure, with a focus on the utilization of transient pipeline simulation models as the Reference Model. The process of identifying and prioritizing the key areas of input uncertainty is highlighted. In particular, experiences in running the procedure for LVL liquids, HVL liquids and natural gas pipelines are discussed. Other areas of discussion and comment include how the new API 1149 update, technical report, can be used for a relative benefit analysis of different candidate CPM techniques for a specific pipeline; and how it might fit in with industry best practices as an API Technical Report (TR).
Evaluating the effectiveness of a CPM implementation via leak testing is paramount to confirm that the performance of the CPM system is acceptable based on a pipeline company's risk profile for detecting leaks. However, leak testing of a CPM system is challenging due to the complexity of the CPM design, as well as the need to stress test the CPM over the breadth of operational scenarios to assess the robustness of the CPM, where test coverage includes steady state threshold sensitivity, transient threshold sensitivity and the threshold switching action. This paper reviews the leak testing challenges encountered during CPM implementation and evaluation, outlines its limitations, and proposes a novel approach to an API RP 1130 recommended test method that can be applied to stress test CPM sensitivity, providing an evaluation of CPM robustness over a range of varying operating scenarios. The concept of the new testing methodology, along with a feasibility study on the automation of the test process, is discussed. Extensive tests are carried out to evaluate and assess the new testing methodology, and a comparison is made with other API RP 1130 recommended leak test methodologies such as parameter manipulation tests, simulated leak tests, and fluid withdrawal tests. The results indicate that the proposed technique has far wider testing coverage compared to existing approaches to leak testing while providing similar sensitivity measurement results and appears promising for use in stress testing sensitivity of CPM systems to gain an understanding of CPM robustness, which in turn has improved the sensitivity and robustness of Enbridge's current leak detection systems.
Rao G, Narasinga (Hindustan Petroleum Corporation Limited) | Bose, M. S. R. K. (Energy Solutions International) | Siva Rao, K. V. (Energy Solutions International) | Srinivasu, R. (Energy Solutions International) | Barley, Jon (Energy Solutions International)
A 13.17 mile (21.20 km) long, 12” diameter black oil pipeline, owned by Hindustan Petroleum Corporation Limited (HPCL), transports Petroleum products such as Furnace Oil & Light Diesel Oil from the Trombay refinery to the Vashi terminal. The pipeline passes underneath Mumbai, one of the world’s most populated cities.
The operational safety, monitoring & maintenance are a concern for the pipeline operator. Operating the pipeline safely is of paramount importance to HPCL. The pipeline was constructed with the consideration of safe operation and regular maintenance regimes are in place to ensure the physical integrity.
Although the pipeline integrity has a very low risk of being compromised through operational activity, there is a potential for loss of product by external interference e.g. theft/pilferage. This paper examines one such case. The pipeline was shut down and the pipeline integrity monitoring system indicated that leaks were occurring. However, due to the low pressure during the shutdown and small volume of the withdrawals, identifying the location of the theft was challenging. In an attempt to locate the theft, an analysis was made using archived data and an RTTM Leak Detection system. The background, methodology and results will be presented.
Pipelines in India and SafetyThe most cost effective, energy efficient and environmental friendly way for transporting petroleum products in India is through the use of pipelines. With 30% lower charges than rail and 4-5 times cheaper than road transportation, pipelines are a major method of transportation for the oil industry in India. Use of pipelines has eased the overburdened rail and road infrastructure and reduced the environmental impacts intrinsic in rail and road transportation. The network of pipelines throughout India helps maintain the supply chain of crude oil, petroleum products and gas within the country and thus pipelines play an important role in balancing supply and demand across the country. With more than 8,751 miles (14,083 km) of product pipelines, 9,532 miles (15,340 km) of natural gas pipelines, 5,878 miles (9,460 km) of crude pipelines and 1,367 miles (2,200 km) of LPG pipeline the pipeline network in India is growing in parallel with its oil industry.
This paper examines the feasibility of Real Time Transient Model (RTTM) based methods for gas pipeline leak detection, elucidates the factors that must be managed for effective gas pipeline leak detection, and examines factors that impact leak detection and location sensitivity.
A growing regulatory focus on minimizing the impacts of ruptures in natural gas commodity pipelines is increasing the pressure on the operators of such systems to provide means of rapidly detecting and locating such leaks. Leak detection systems have become standardized components of liquid commodity pipelines over the last few decades, but have not been emphasized for natural gas systems.
Although many methods have been used to detect leaks in liquid systems, the most commonly used approach uses real time transient models and a mass-balance approach to detect commodity losses. The approach is extensible to gas systems in a fairly straightforward manner, and this paper will discuss such implementation. However, it is worth nothing that gas systems have certain differences that make them distinct from liquid pipeline systems. One difference is that gas pipelines, especially if they are part of or support gas distribution, have the potential to be far more highly networked, branched and looped than liquid transportation systems. Gas is a far more highly compressible commodity than most liquids are, and this has ramification for desired levels of instrumentation and speed of response. Finally, gas pipelines are more highly typified by maintenance requirements that can interfere with or degrade the performance of RTTM systems.
Another significant different between liquid and gas pipeline leak detection requirements is that generally, in a liquid line, a very large leak may be quickly identified by rate of change alarms. In contrast, a large leak in a gas pipeline, because of the compressibility of the gas, will cause much slower changes in the pipeline pressure. A gas pipeline therefore, may need to rely on an RTTM based leak detection system even for the reliable and timely detection of very large leaks.This paper attempts to illuminate these issues and equip the reader to understand and deal with them.