In 2014, Enbridge published a request for proposals to develop and provide a solution on a specific type of long seam cracks in a 26” pipeline. In-line inspection technologies available at the time were not able to consistently and accurately characterize the crack threat, although the line was successfully hydrostatically tested in 2015. During the early stages of the project, NDT Global analyzed in detail Enbridge’s requirements, including the specific challenges, spool type, seam weld characteristics etc. and provided different proposals to Enbridge. In 2016, both parties signed a development contract to develop and build a 26” Next Generation Crack Inspection Platform (Proton). The project was divided into various stages to support a successful project that met performance requirements based both on pump tests and a field trial supported by investigative digs and coupon cutouts. The robot developed is a highly versatile crack inspection platform: it allows to be set up in a configuration optimized for the given threat, pipeline conditions, inspection speed and medium characteristics. This optimization of the configuration allows choosing the optimum measurement modes for flaws in the base material and in the seam weld independently. Additionally, the local wall thickness even in the seam weld is measured accurately. These capabilities allow the operator to collect the best data for each situation. Feeding the information into the crack management program allows Enbridge to maintain the target reliability of the asset. The robot was utilized successfully in the 26” pipeline. Processing, data analysis and reporting were performed within pre-agreed periods. Initial field findings and lab tests show high correlation of ILI and real flaws and proof the stated accuracy of the new service. The authors will present in detail some of the specific challenges of the pipeline system and limitations of available crack inspection technologies. Validation results from in-the-ditch non-destructive examination and destructive freeze breaks including cross sections from flaws with complex morphologies will be shown. Performance statistics and comparison to previous inspection results will be used to demonstrate that the new robot can be used as part of an effective crack management program.

Following what was considered a routine realignment of liquid product lines and tankage at a storage and transfer facility, an incident occurred that resulted in significant movement of a 20-inch pipeline, causing a large section of it to fall from its supports. The event also resulted in the failure of a gasket at a valve flange and loss of containment. The alignment activities and pump startup were investigated for the potential to generate a hydraulic transient capable of generating sufficient force to cause the movement. A transient hydraulic model of the fluid in the piping as it was aligned at the time of the event was generated to assist in determining the cause and to help prevent a similar occurrence in the future. Several scenarios were modeled and are discussed in this paper: 1) pump shutdown from steady flow, 2) pump start up with the discharge valve open, 3) pump startup with the discharge valve closed, and 4) pump start up with a vapor cavity present near a closed valve at the high point in the line. Pipe stress and finite element analysis were used to assess the displaced pipe and to determine if it could be placed back into service. The piping stress analysis indicated that the highest stress in the piping was below the yield stress of the material. Results from a detailed finite element analysis with material nonlinearity confirmed that there was no global plastic strain in the piping due to the event. This left a potential for local plastic strain due to the impact of the pipe against any hard surfaces, and this was addressed with visual examination. In the end, the pipe was lifted back onto the supports, lateral restraints were added at pipe support locations, and procedural changes were implemented to reduce the likelihood of future events.

In the production management of offshore oil field, the production of single well is very important for reservoir understanding and production allocation. Because of the high cost and short life of the conventional underwater flowmeter, the virtual metering technology has gradually become a trend. ESP (electric submersible pump) is a kind of mechanical equipment commonly used in artificial lift oil recovery method, and used in offshore oil field development and production. Based on the characteristics of ESP and real-time production data, this paper establishes the oil well flow inversion model and proposes a fast calculation method to meet the application requirements, which provides a new method for the acquisition of production information of offshore oil fields.

The Enbridge Liquids Pipeline system is comprised of a large number of facilities including storage terminals, pump stations, injection sites, and delivery sites. Given the vast amount of small diameter piping (SDP) within company Pipeline facilities, SDP represents a significant portion of total facility integrity risk. An event such as equipment failure or product release can cause significant business impacts, and adverse consequences to the environment and/or safety of operations personnel. A quantitative risk based approach is required in order to establish robust, risk-based plans and programs to maintain the integrity of these SDP sections. Small diameter piping lengths are relatively short. Consequently, it is impractical to use SDP length as a unit of likelihood and risk measure. Instead, the preferred methodology is to determine the total number of assemblies for each type of SDP. In support of this approach, an inventory of SDP sections throughout the system has been gathered. For illustrative purposes, an example of a small diameter section would be a pressure transmitter branch connection. The isolatable section that would be risk assessed would start from the surface of the main station piping connection and continue up to the transmitter. This paper presents the framework for likelihood and consequence assessment of SDP based on the system description above. This framework quantitatively estimates the risk of SDP failure and risk-ranks SDP sections in support of implementing and establishing a system wide Risk Based Inspection and Maintenance program for SDP.

Onshore, liquid pipelines are often modeled with isothermal models. Ignoring thermal effects is justified because thermal effects are of secondary importance and because the data, such as burial depth, soil thermal conductivity, soil heat capacity, and soil density, required to accurately predict thermal behavior in buried pipelines is not known accurately. In addition, run speeds are faster for isothermal models than for rigorous thermal models, which is particularly important in real-time models. One condition where thermal effects become important is when a pipeline is shut-in. Pumps increase the temperature of the fluid, so the fluid temperature is, on average, greater than ambient temperature. When a pipeline is shut-in, the temperature decreases causing a corresponding decrease in pressure. Since an isothermal model does not account for this behavior, the decreasing pressure can be misinterpreted as a leak. This paper discusses a strategy for correcting the model to properly account for the behavior in shut-in conditions. The strategy is applied to real-time pipeline models using Synergi Pipeline Simulator (SPS), although the method is applicable to any isothermal model.

The use of drag reduction agents (DRA) can be a decisive factor in determining the technical and economic feasibility of new pipelines projects, meeting the demands not foreseen and seasonality accommodation without large investments in infrastructure. Knowing the friction reduction mechanism and its impact on the operating procedure of existing products is essential in order to have the guarantee of the benefit for your application. Most of the works published report field experiences obtained from its application, seeking to determine the influence that internal and external factors have on the polymer. Knowing these effects is essential for better application performance. However, few authors have sought to identify the best way to operate an existing pipeline with DRA, with either an increase in capacity or an energy reduction. Operationally, the use of drag reducing agents may decrease the currently used arrangement of pumps, or even the complete shutdown of a pumping station. In this context, the use of drag reducers may be a suitable solution for decreasing power consumption in fluid transport pipelines of petroleum and derivatives. This paper presents a case study of the application of drag reducing agents in a Brazilian high-energy pipeline. It features five intermediate pumping stations and three withdrawal points along its nearly one thousand kilometer stretch. With the aid of a computer simulation software, it is proposed a methodology to evaluate the best application condition, minimizing pump costs, polymer volume and meeting the scheduled demand of the month. This methodology first sought to validate the computational model of the pipeline. It was made a historical survey and inserted into the simulator, in order to reproduce faithfully a monthly operation. A sensitivity analysis is performed to determine which pump stations are most relevant. It was established an initial concentration of polymer to be injected in the sending refinery, aiming the reduction of arrangement or total shutdown of the subsequent station and keeping volume delivered on all points. The other bases remain working according to the operation of the month. This procedure is then repeated for the other bases, resulting in a combined and continuous injection, minimizing the operating costs. An economic evaluation is finally performed to quantify the benefits of this application. A reduction in energy consumption of 49% was noticed, and considering the costs with DRA, the monthly movement had a 35% drop in the total costs of operation.

Considering market’s diversified demand and transport economy, large volumes of various refined products commonly move down the pipeline in batches, which are pumped at pump stations and delivered to respective delivery stations. The integrate detailed scheduling optimization is a sophisticated problem due to the characteristics of multi-product pipelines, such as market-oriented, fluctuated demand, various processing technique and complicated hydraulic calculation during batch migration. The integrate detailed scheduling optimization has been widely studied during the last decade, however, most of them studied pipeline scheduling and pump scheduling separately. Besides, the proposed methods are mathematical models, whose computational efficiency greatly decreases in large-scale pipeline scheduling, let alone in the problems coupling with pump scheduling. Aiming at this problem, this paper presents a novel depth-first searching approach based on flowrate ratio to deal with the detailed scheduling of operations in a multi-product pipeline with multiple pump stations. As for each single time interval, the proposed method decides an ideal flowrate ratio according to current status, then solves out the optimal flowrate that mostly conforms to the ideal ratio and satisfies all operational constraints, and finally updates information for next time interval. However, during the computational procedure, backtracking method would be adopted to modify the previous flowrate ratios and recalculate new flowrate when the actual delivered products are insufficient. Finally, a case tested on a Chinese real-world pipeline with 6 delivery stations is given to demonstrate the veracity and practicability of the proposed method. From the results, computing time of the case is within 1 minute, and the solved detailed scheduling plans can fulfill demand with stable pump operations. Besides, the proposed approach is scarcely influenced by the scale of pipeline structure and time horizon, so it is also applicable to the long-term scheduling of a pipeline with many delivery stations.

High pH Stress Corrosion Cracking (HpHSCC) is a significant threat to the buried pipelines, which are protected through simultaneous coating and cathodic protection strategies. In the past decades, extensive research has been devoted to assessing the influence of environmental and metallurgical factors on the susceptibility to HpHSCC. With reference to mechanical factors, previous studies employed either slow strain rate or constant amplitude testing methods. However, the pressure fluctuation data extracted from pipeline operations has indicated that pipelines experience highly variable amplitude loading conditions during their service. Accordingly, an important consideration in managing HpHSCC is load interaction. Statistics show a higher probability of HpHSCC failures within the 30 km downstream from pump/compressor stations where the pipeline steels experience elevated service temperatures, with incipient higher susceptibility to HpHSCC. However, the pipeline sections within the 30 km downstream from pump/compressor stations also experience the underload-type of pressure fluctuations that feature a maximum pressure close to the design limit, frequent and large amplitudes of depressurization, resulting in low stress ratio, R (minimum stress/maximum stress), and many smaller pressure fluctuations (minor cycles) with R ratio closer to +1.0. It has been well characterized that the underload-minor-cycle-type of pressure fluctuations has the significant acceleration effect on crack growth rates in near-neutral pH (NNpH) environments. However, the effect of the underload-type of pressure schemes on HpHSCC crack growth has not been well developed. In this research work, a cathodically protected X65 steel specimen in the developed high pH solution, composed of 1N Na 2 CO 3 and 1N NaHCO 3 , was subjected to different loading conditions. These loading waveforms simulate underload cycles (R = 0.5), minor cycles (R = 0.9) and variable amplitudes consisting of both underload and minor cycles, respectively. The HpHSCC test results showed that the highest and lowest crack growth rates were obtained in high and low R ratio constant amplitude loading conditions, respectively. Furthermore, an intermediate crack growth rate was obtained under variable amplitude loading condition. These results indicate that the underload cycles retard crack growth rate in high pH environments.

In the majority of liquid pipelines, the pump station discharge pressure ranges are much greater than the pressure ranges experienced at the suction end of the downstream pump station. Consequently, the cyclic pressure induced fatigue damage accumulation rate is greater at the discharge end than at the suction end of a given pipeline segment. In completing an integrity assessment of a fatigue susceptible feature, assuming that the pump station discharge cyclic pressure profile applies to all features in the line segment is conservative. This conservative assumption can lead to un-necessary repairs, unintentional damage from over-prescribed maintenance, or inefficient decisions regarding maintenance action prioritization. The following paper presents the results of a Canadian Energy Pipeline Association (CEPA) initiative to develop a simple approach to define the cyclic pressure history at any point in a liquid pipeline segment based on the bounding discharge and suction pump station Supervisory Control and Data Acquisition (SCADA) pressure time history data. The approach was developed based on collected operating pipeline SCADA pressure time history data for line segments with intermediate measurement points which could be used to validate the developed model. The pressure time histories for all the locations were analyzed using a Rainflow cycle counting technique to develop pressure range spectra (i.e. histograms of pressure range events) and the cyclic pressure severity of each of the time histories was characterized by the Spectrum Severity Indicator (SSI). The SSI represents the number of annual 90MPa hoop stress cycles required to accumulate the same fatigue damage as the actual pressure spectrums. The technique presented in this paper illustrates how to infer the pressure range spectra or SSI at intermediate locations. The technique is shown to be a significant improvement (i.e. higher location specific accuracy) than either applying the discharge pressure spectrum or applying a linear interpolation between discharge and suction conditions in fatigue life assessments. The liquid pipeline cyclic pressure characterization technique presented in this paper will permit integrity assessment or severity ranking of features along a pipeline to be based on an accurate local pressure profile rather than an upper bound. This understanding will help to improve the accuracy of defect loading, one of the three main pillars in integrity assessment (i.e., loading, geometry, materials) for defects susceptible to cyclic loading (e.g., cracking, mechanical damage).

Vibration related issues can be a challenging part of pipeline integrity management, because they are frequently difficult to predict, diagnose, and remediate. Often, vibrational issues are not even considered until pipe movement is observed or failures occur. A wide variety of vibration problems are associated with pumps and compressors, and piping at pumping stations are often susceptible to vibration related issues. Excessive piping vibration may result in leaks at connections and flanges, and fatigue failures can occur, leading to leaks that present safety and environmental concerns. The energy responsible for pipeline vibration is usually provided by rotating or reciprocating pumping equipment, and is transmitted to the piping either by direct mechanical contact, pressure pulsations, or turbulence in the pumped fluid. Vibration problems usually occur when a mechanical natural frequency of the piping system, an acoustic natural frequency of the contained fluid, or both, is excited by the driving force. In this paper, a brief overview of vibration issues that occur in pipeline facilities is presented. Next, a selection of case studies is provided to illustrate some of the types of vibration induced failures that have been observed at pipeline facilities, and how they were addressed and resolved. These examples provide some insight into how to potentially avoid such issues, or if they occur, how to identify and mitigate them.

As the primary means of refined products transportation, multi-product pipeline plays a vital role in connecting refineries to local markets. Once disruptions occur, it will cause security issue on oil supply to downstream markets, even on the economy and stability of society. Based on the conventional reliability theory and detailed scheduling method of multi-product pipeline considering hydraulic constraints, this paper firstly proposes a multi-module systemic approach for the supply reliability analysis of multi-product pipeline under pump units failure conditions. Pump units are important corollary equipment in multi-product pipeline and their failure would affect the pipeline normal operation and downstream oil supply greatly. The approach includes three modules, namely, pump units analysis module, pipeline system analysis module and reliability evaluation module. In the pump units analysis module, Failure Mode and Effects Analysis (FMEA) method is adopted to analyse the correlations between pump units failure modes and causes. The Monte Carlo simulation method is employed to generate different failure scenarios based on the estimated failure rate of pump units. In the pipeline system analysis module, the detailed scheduling method of multi-product pipeline is adopted to calculate the maximum supply capacity for all delivery stations under a specific scenario. Due to the difficulty in solving detailed scheduling problem considering hydraulic constraints directly, two mixed integer linear programming (MILP) models are established. In the reliability evaluation module, the indexes of shortage, probability and adequacy are calculated to analyse the supply reliability quantitatively from global perspective and individual perspective. Finally, the proposed approach is applied to a real-world multi-product pipeline in Zhejiang, China. It is proved that this approach could provide significant guidelines for the supply reliability analysis of multi-product pipeline.

Internal pressure fluctuations during pipeline operations could contribute to crack growth in steel pipelines. These pressure fluctuations create a variable amplitude loading condition with large amplitude cycles at near-zero stress ratio, R (minimum stress / maximum stress) and small amplitude cycles (minor cycles) at near +1 R ratio which can both affect crack propagation. Mean stresses fluctuate with pressure due to fluid friction losses proportional to the distance from the pump/compressor station. A deeper understanding of mean stress sensitivity on crack growth rate in steel pipelines is sought. The aim of this research is to retard crack growth in pipelines by prescribing pressure fluctuations, thus controlling mean stress effects on imperfection growth in steel pipelines under a near neutral pH environment. This study shows that prescriptive mean load pressure fluctuations can be used to reduce crack growth rates in steel pipelines, thus expanding pipeline integrity management methods.

Pacific Gas and Electric Company owns and operates an extensive network of over 10,700 km (6,700 miles) of gas transmission pipelines, much of which is under 16″ diameter and operates at less than 27.5 bar (400 psig), making them difficult to inspect with free swimming in-line inspection (ILI) tools. Additionally, many piggable pipeline sections are multi-diameter and have numerous 1.5D fittings, some of these in back to back configuration, requiring tools that are not currently available. Following several failed attempts to inspect PG&E’s 12″ × 16″ pipelines in 2015 using existing ILI tools, and after working to modify a 12″ × 18″ tool for lower pressure service in 2016, PG&E and ROSEN decided to collaboratively develop new, specially designed, 12″ × 16″ geometry and axial MFL tools. The goal of this project was to develop tools that could meet both the PG&E pipeline passage requirements and allow for an acceptable speed profile. The need to inspect a total of 16 pipeline sections in the long-term ILI Upgrade Plan, in this size range, justified the investment in these new tools. The service provider embarked on a new ILI tool design process including design, manufacturing, fabrication and testing at their facilities in Germany. Through this process, a number of unique ILI tool design features to lower tool drag and improve ease of collapsibility were implemented, resulting in a tool that far exceeds existing industry capabilities. To confirm the tools’ capabilities before their first use in a live gas transmission pipeline, pump testing in water, as well as in compressed air, was performed. In late 2017, using these tools, PG&E inspected two previously unpiggable 12″ × 16″ low-pressure pipelines successfully. In this paper, the process of developing these tools will be discussed. The test program will be reviewed comparing findings under controlled conditions in water and compressed air with pig run behavior in the live pipelines. The analysis also provides an assessment of the operating conditions that are deemed necessary for the inspection tool to gather a good quality data set.

Hydrostatic testing is a costly, operationally-impactful method of verifying seam integrity in low frequency electric resistance welded (LF-ERW) line pipe. Pipeline operators seek an alternative seam assessment method that provides a sufficiently conservative integrity assessment without the potentially negative impacts of hydrostatic testing. As in-line inspection (ILI) and field nondestructive evaluation (NDE) improve, pipelines that have been historically hydrostatic tested can now use ILI to ensure operational integrity. The improved ILI technology assessed in this work is an enhanced ultrasonic crack ILI tool with higher circumferential resolution and finer axial sample intervals. Magnetic ILI data from previous assessments is used to assist in anomaly identification. In addition to utilizing NDE technologies such as phased array, the emerging full matrix capture (FMC) imaging method that quantifies the size, position, and orientation of seam weld anomalies was examined. This paper discusses the work performed to ensure the efficacy of the improved ILI and NDE methods to accurately detect and quantify all anomalies that could possibly fail a hydrostatic test. An early step in the process was removing three sections of pipe from service for technology calibration and assessment. Each spool was examined with ILI technology in a pump-through facility, inspected using many NDE methods and then destructively tested. These results were communicated to ILI analysts and used to calibrate and improve the interpretation of the inspection results. Then the pipeline was inspected as part of the scheduled integrity assessment. Using field evaluation of anomalies detected by ILI, pipes were selected for removal from service to examine destructively. This paper presents the inspection and destructive testing results in addition to prognosis for the use of the ILI in lieu of hydrostatic testing for LF-ERW pipe.

Pipelines are designed to operate below a maximum operating pressure in service. However, there are pressure fluctuations during operation. The presence of pressure fluctuations creates a drive for crack growth in steel pipes. In order to prevent catastrophic failure of pipelines, there is need for better understanding of the contribution of pressure fluctuations to crack growth rate in steel pipelines. Analysis of pressure fluctuation data in oil and gas pipelines shows that there are different types of fluctuations in a pipe due to friction loss with distance from the pump or compressor station. All these fluctuation types show a form of variable amplitude loading classified in this research as underload, mean load and overload. Studies of some structural systems shows that underload can cause acceleration of crack growth while retardation of crack growth is observed after an overload. This research aims to apply pressure fluctuations to manage integrity of steel pipelines through a novel approach of load sequence involving underload and overload in near neutral pH environment. Clear knowledge of the effect of load interaction involving load sequence of underload and overload is vital to control crack growth in steel pipelines under near neutral pH environment. The result of crack growth rate under different load sequence on X65 steel indicate that increase in overload ratio of 2, 3 and 4 caused an increase in crack growth rate of 1.68E−3, 1.89E−3 and 2.31E−3 mm/block respectively. These results are compared with results from other tests under variable amplitude without load sequence. Analyses were carried out on the morphology of the crack tip and the fracture surface after the test.

Invariably, oil pump station piping layouts may contain multiple dead-legs brought about by closed valves at one end of side branches, while flows continue through the main runs. During the transportation of heavy crude through the pump station, these dead-legs will be filled with this crude. When a light crude batch is introduced next into the pipeline, following the heavy crude ahead, two phenomena will occur. First, contamination between batches at the interface of the two crudes will occur due to axial turbulent diffusion along the length of the pipeline itself. Second, as the light crude flows through the pump station, and passes by each dead-leg containing residual heavy crude from the preceding batch, the heavy crude trapped in these dead-legs will start to drain out into the passing light crude in the main run. This causes further contamination and spreading of the mixing zone between the two batches. The second source of contamination, which is addressed in this paper, could cause appreciable contamination particularly for large dead-leg sizes and numbers. A computational fluid dynamics (CFD) model has been developed to quantify the drainage rate of the contaminating crude into the main stream and its impact on widening the mixed zone (contamination spread) between the two batches. Two drainage mechanisms of the heavy crude in the dead-legs into the main stream of the light crude have been identified and quantified. Finally, potential innovations to mitigate contamination due to dead legs are presented and quantified for their respective effectiveness in minimizing the contamination spreads between batches of different crudes.

An electrical Variable Frequency Drive (VFD) is a device that controls a motor by varying the frequency and voltage supplied to the motor. Frequency (or hertz) is directly related to the motor’s speed (RPMs). If an application does not require an electric motor to run at full speed, the VFD can be used to ramp down the frequency and voltage to meet the requirements of the electric motor’s load. As the application’s motor speed requirements change, the VFD can simply turn up or down the motor speed to meet the speed requirement which in turn controls the output of the connected equipment, in this case a pipeline pump (i.e. flow and pressure). This device is important in pipeline applications as it provides the operator with improved control over the critical parameters of the pump and in doing so increases pumping efficiency while reducing energy costs. Enbridge Liquids Pipelines has gradually introduced more VFD units on its mainline pumping systems since 1994. To date, 50% of the mainline pumps in the Enbridge Liquids Pipeline network operate under the control of a VFD. There is now sufficient historical operating data on those assets in order to quantify the benefits related to this particular system. This paper focuses on the operational reliability aspects of the VFDs and equipment controlled by the VFD. This includes failure probabilities and throughput performance over the life cycle of the system but excludes technical implications such as VFD selection, application, specification or design. From a pure maintenance perspective, VFDs contribute to a marked improvement on pumps in terms of failure reduction. For general pump failures including components such as mechanical seals, bearings, shaft, wear rings or couplings, it is demonstrated that the probability of failure is lower on pumps combined with VFDs compared to pumps without VFDs. In terms of mean time between repairs (MTBR), this equates to an increase of 65% relative to pumps with VFDs. All mainline pumps in Enbridge are driven by electric motors. With regards to drive motor failures, there is also a significant reduction in repairs; MTBR increases by approximately 25% on VFD driven electric motors. Another factor which can enhance the benefits associated with VFDs is the sparing options. In Enbridge Liquids Pipelines, there are two types of sparing options related to VFDs: • Dedicated VFDs (1 VFD controlling a single mainline pump) • Shared VFD (1 VFD shared between a set of mainline pumps) with back-up across the line starting. The throughput performance between the above mentioned existing options has been shown to differ substantially. On a specific pipeline built initially with shared VFDs then fitted with Dedicated VFDs, the number of pump failures decreased by 60% leading to a throughput loss reduction of 66%. However, while the VFD helps preserve the asset it runs in conjunction with, the VFD itself introduces a high frequency of failures in the overall pumping system. For the systems studied in Enbridge pipelines, adding a VFD increases the frequency of downtime events by 118%. However, these failures are short in duration which in the long term add up to less downtime (276% less) on a pumping system with VFD. Finally, VFD units have a high capital cost which can double the cost of ownership of a pumping system over the life cycle of the asset. However, this cost can be offset by the increase in availability provide by the VFD but this needs to be vetted through a Life Cycle Cost analysis.

The prevailing leak detection systems used today on hazardous liquid pipelines (computational pipeline monitoring) do not have the required sensitivities to detect small leaks smaller than 1% of the nominal flow rate. False alarms of any leak detection system are a major industry concern, as such events will eventually lead to alarms being ignored, rendering the leak detection system ineffective [1]. This paper discusses the recent work focused on the development of an innovative remote sensing technology that is capable of reliably and automatically detecting small hazardous liquid leaks in near real-time. The technology is suitable for airborne applications, including manned and unmanned aircraft, ground applications, as well as stationary applications, such as monitoring of pipeline pump stations. While the focus of the development was primarily for detecting liquid hydrocarbon leaks, the technology also shows promise for detecting gas leaks. The technology fuses inputs from various types of optical sensors and applies machine learning techniques to reliably detect “fingerprints” of small hazardous liquid leaks. The optical sensors used include long-wave infrared, short-wave infrared, hyperspectral, and visual cameras. The utilization of these different imaging approaches raises the possibility for detecting spilled product from a past event even if the leak is not actively progressing. In order to thoroughly characterize leaks, tests were performed by imaging a variety of different types of hazardous liquid constitutions (e.g. crude oil, refined products, crude oil mixed with a variety of common refined products, etc.) in several different environmental conditions (e.g., lighting, temperature, etc.) and on various surfaces (e.g., grass, pavement, gravel, etc.). Tests were also conducted to characterize non-leak events. Focus was given to highly reflective and highly absorbent materials/conditions that are typically found near pipelines. Techniques were developed to extract a variety of features across the several spectral bands to identify unique attributes of different types of hazardous liquid constitutions and environmental conditions as well as non-leak events. The characterization of non-leak events is crucial in significantly reducing false alarm rates. Classifiers were then trained to detect small leaks and reject non-leak events (false alarms), followed by system performance testing. The trial results of this work are discussed in this paper.

A hydraulic transient occurs when there is a sudden change in the steady state condition of a fluid in a pipeline. The rapid change in velocity of a fluid causes a pressure wave to travel along the pipeline, potentially causing damage to the equipment and piping. Usually, different scenarios are studied depending on whether the fluid is being injected or delivered from the pipeline into a tank. The most commonly studied causes of sudden fluid velocity change in a pipeline are: closing of a fast acting valve (ESD or control valves which close within seconds) and stopping or starting of pumps. When a pipeline is delivering fluid into a tank, the closure of a valve can completely block the flow and create transient surge pressures that exceed acceptable pressure limits, and require mitigation. Although the closure of a fast acting valve is a commonly analyzed scenario, the closure of a motor operated valve (MOV), which is less commonly analyzed, can also create surge pressures which can put the pipeline at risk. There are three characteristics of an MOV that can significantly impact the surge pressures it creates when it is closed. These valve characteristics are: flow coefficient, valve curve and stroke time. Hydraulic simulations were performed to study the effect of these three valve characteristics on transient responses when delivering from pipelines into tanks. Simulation results show that a faster stroke time leads to higher pressure surges, as well as a valve with a quick closing or linear curve. However, the flow coefficient of the valves will have varying effects on transients depending on the piping system being analyzed. The purpose of this paper is to not only highlight the importance of valve characteristics when modeling transient surge events but also to provide key learnings that can be used to design safer delivery terminals.

The pump station at Kinder Morgan Canada’s (KMC) Kamloops facility has been in operation for 60+ years. In that time the four parallel pumps in the facility have each moved an estimated 1 billion barrels of crude oil, gasoline and diesel from the Sherwood Park area of Alberta and the oil fields of NE British Columbia to the west coast of Canada and into Washington State. This paper describes the innovative project (see Figure 1 above) where the four existing multi-stage parallel pumps at the Kamloops facility were replaced with two single stage series pumps. This paper assumes the reader has a working knowledge of pump hydraulics. A detailed list of all acronyms used within this paper is located at the end of the document under the heading entitled “Nomenclature”.