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.
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.
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.
Significant financial and environmental consequences often result from line leakage of oil product pipelines. Product can escape into the surrounding soil as even the smallest leak can lead to rupture of the pipeline. From a health perspective, water supplies may be tainted by oil migrating into aquifers. A joint academic-industry research initiative funded by (Pipeline and Hazardous Materials Safety Association) PHMSA(1) has led to the development and refinement of a free-swimming tool which is capable of detecting leaks as small as 0.01 L/min (0.03 gallons) in oil product pipelines. The tool swims through the pipeline being assessed and produces results to the end user at a significantly reduced cost compared to current leak detection methods. Above Ground Markers (AGM’s) capture low frequency acoustic signatures and digitally log the passage of the tool through a pipeline. A tri-axial accelerometer system gives the odometric position of the ball, and has the accuracy of standard instrumented pigs. Several other types of sensors like temperature, and pressure, are also present in the ball and collect useful data.