When transporting multiple products in a pipeline, it is important to always understand the location of the head and tail of each batch. The operator will know where batch interfaces are in real-time and be ready to swing the valve at the exact time a batch arrives at a station to deliver product to the right storage tank or an end-customer with minimal contamination. It is relatively easy to track multiple batches in a pipeline with no elevation changes, and a fixed internal diameter. However, it is far more complex to track multiple batches in a pipeline with drastic elevation changes and different sizes in diameter. Column separation of the liquid, also known as slack, occurs when the pipeline pressure drops below the vapor pressure calculated at the liquid temperature in a specific area of the pipeline. This effect reduces the amount of liquid volume contained within the pipeline region, changing the actual physical position of the batch head and tail interfaces, and reducing the accuracy of the volume within the region and the corresponding Estimated Times of Arrival at stations. Draining or filling a pipeline section by delivering product at a different rate from what injected causes the same effect. A scientific approach to calculate the areas of slack and volume contained within a pipeline should provide sufficient information to track batches with a high degree of accuracy. However, it is neither simple nor straightforward to simulate this phenomenon offline, and it is much more challenging in an online, real-time environment. Online, additional complexities affect how batches and their interfaces are tracked, causing a big discrepancy between Estimated and Actual Time of Arrivals. This paper discusses an empirical approach developed to calculate the volume contained within a pipeline region by tracking the volume entering and leaving the region. Estimated and Actual Times of Arrival are within a 15-minute time window after a batch has traveled a total distance of 1,200km with drastic elevation changes along the route. This method has proven that batch tracking can be highly accurate and reliable with less of the theoretical assumptions used in a hydraulic simulation package, with no need to model every single characteristic of the pipeline in detail. This removed the uncertainties that attend those assumptions and allowed this system to perform well on a pipeline with severe slack flow and draining/filling operations.

Throughout North America there are many crude oil storage tank facilities — also called terminals — serving as hubs, transfer points and storage. Safety precautions such as pre-service integrity testing, cathodic protection, primary and secondary containment measures, and grounding techniques have been utilized to assure safety as a top priority. These tanks undergo an in-service API 653 external inspection at least every 5 years, and are taken out of service to undergo an API 653 internal/external inspection at least every 30 years [1], [2], [3]. For these aboveground storage tanks, the bottom plate is the most vulnerable area to corrosion [4] and is also the most challenge area to inspect visually. Both sides (product-side and soil-side) of the tank bottom plate are prone to high rates of corrosion in comparison to other components such as the roof and shell [5]. Corrosion generally starts with coating defects such as air or water ingress to underling layers and exposing the steel to uncontrolled environmental factors. Internal inspection can be performed using ultrasonic measures to calculate the sheet thickness, however, external inspection is impossible without having access to the tank bottom. This paper will introduce a novel inspection method for external monitoring of the surface of the tank bottom plate in real-time. The proposed technique proactively approaches the problem by predicting the corrosion before it occurs. In this technique an array of microwave-based sensors operating at ISM band (2.57 GHz) are introduced for defect prediction. The array is composed of equally-distant and identical microwave spiral ring resonators (SRR) [6] that are electromagnetically coupled to a transmission line. All resonances created by the array elements merge in one band-stop frequency response with very high isolation. Once the sensors’ environment is altered by any defects such as an air breach, liquid ingress [7] or corrosion initiated, a resonance shift will occur indicating coating risks. To prove the concept, an initial prototype for small tanks of 3–5 ft. diameter is investigated. Two-port system data illustrates that in case of a coating defect, the frequency profile accordingly changes and provides a signature. The obtained data is used to predict possible corrosion in timely manner. The proposed sensor array enables external monitoring of tank bottoms surface where visual inspection is impossible while the tank is in-service.

Leakage in oil and gas infrastructure, often cause significant financial losses, severe damage to the environment and raises public concern. In order to minimize the impact of spills, quick detection of a leak and a rapid response are needed. The systems currently employed to detect pipeline leakage range from simple visual checking to complex hardware and software systems such as mass balance, pressure point analysis, flow deviation, acoustic emission systems, and fibre-optic-based sensing technologies. These methods are useful, but there are certain limitations. The main drawback of the majority of these leak detection technologies is that they detect leakage indirectly, often unable to detect the leakage until the major spill. The preventive monitoring system and direct detection of hydrocarbon leakage are urgently needed to enable fast response and timely repairs with less deleterious effects. Research is being conducted for the development of a functional prototype and environmental testing of in-situ carbon nanotube (CNT) nanocomposite based sensors for hydrocarbon leakage detection. The CNT nanocomposite offers a unique approach to the direct hydrocarbon leakage detection in pipelines and aboveground storage tanks (ASTs). Expanding the study from the previous report of sensor characteristics under the optimal ambient condition, it was further investigated to identify the sensor performance under harsh conditions such as the underground (exposed to the soil) with compost and moisture, high pressure, changing temperature and long-term exposure to the outdoor environment. Investigation of the sensor behavior is studied, and a performance matrix is developed that accounts for the change in sensor response to various environmental conditions. Results showed that the proposed CNT nanocomposite sensor was applicable under given conditions with immediate responses while maintaining high sensitivity to the hydrocarbon leakage. Once a list of sensor detection specifications is defined, it is anticipated that the CNT sensor technology is applicable as part of a robust, reliable and accurate early detection system for the pipeline industry.

Reliability, Availability and Maintainability (RAM) models were first developed in Enbridge Liquids Pipelines in 2006 and in the last 3 years have contributed over $200 Million in capital cost avoidance while maintaining or improving the reliable design and operation of the pipeline system. These models constitute a very effective, factual and dependable tool to assess the throughput performance of a pipeline system over its entire life cycle or a specified time of interest. In addition, the RAM model cost is a small fraction of the overall monetary benefit, in the order of 1%, hence making RAM models a highly leveraged activity. The concept of a RAM model stems from Reliability Block Diagram methods (also known as Dependent Diagrams). Interaction of large, complex and multi layered systems can then be analyzed using the Monte Carlo simulation methods (or Stochastic Discrete Event Simulation) hence quantifying the output of the entire system with greater accuracy than other estimating tools or methods. Over 10 years, Enbridge Liquids Pipelines has developed its own failure database for equipment and operational events consequently almost all model inputs are based on in-house data rather than industry generic data, making the model output more robust, accurate and appropriate for internal use. Initially, in Enbridge Liquids Pipelines, RAM models were mainly built to assess and confirm the design capabilities of future pipelines designs and assist in the optimal selection of specific design options. Because of the effectiveness of the tool combined with the current cost constrained business environment, the company is moving towards building RAM models for assets already in operation in order to optimize their performance. This is proving to be an extremely cost effective addition to internal decision making processes. The approach has been used in risk based budgeting, asset maintenance, design modifications and throughput optimization initiatives. In various industries including Oil and Gas, RAM models have proven their worth over time as an effective cost avoidance tool. This approach has now been successfully deployed in the Pipeline Industry at Enbridge. As an example, a RAM model conducted during the design phase of a pipeline project saved $28 million in capital by proving that an additional storage tank and significant new infrastructure was not required. Another benefit of RAM models has been their ability to confirm or counter stated assumptions by internal stakeholders. Equipment upgrades and equipment sparing decisions are often seriously debated and costly decisions may not always be based on complete economical foundations but rather on avoiding past negative experiences or by following basic guidelines that are less than optimal. When a project or operational team needs to find an alternative, a RAM model is a tool of choice to evaluate, and justify the best option. Because of its proven value, RAM models are now an integral part of Enbridge Liquids Pipelines Design Standards and are used on all large projects. Models recently built for operational pipelines delivered similar value so in the near future the work will be expanded to encompass the entire existing network of integrated pipelines to improve on performance and operational costs.

The “A” manifold header replacement is presented within this paper as a case study to demonstrate how laser scanning (both of the existing piping and the newly fabricated spools) as well as off-site spool fabrication and testing, when combined with detailed pre-planning of activities and mapping of facility impacts to optimize the execution of a complex in-situ piping modification with an extremely tight facility outage window. This paper explores the design and execution strategies used for the complete replacement of the southern portion of the NPS 24 piping header in “A” manifold at Enbridge’s Sarnia Terminal as contained within the Project Leave-to-Open packages. The piping header was fully replaced and upsized to NPS 30 as part of the Line 9B Reversal & Line 9 Capacity Expansion Project during a four-day facility outage in the summer of 2014. The work was managed by Enbridge Pipelines Inc. and executed by a regional industrial construction company (“contractor”). The header is a straight run of approximately 55m and includes 14 process tie-points. Certain stages of the replacement required a total shutdown of Sarnia Terminal, which mandated a very tight execution window. To enable completion of the work within the allotted outage, the new piping header was fabricated and hydrostatically tested in three sections at the contractor’s fabrication shop. All on-site tie-ins were designed to be bolted connections. The factors which influenced the design and the staged execution strategy used during the outage are discussed in detail within the paper. Three key operability and technical factors influenced the design and execution strategies employed. Firstly, the Sarnia Terminal is fully interconnected to allow delivery to and from all 17 storage tanks on all 5 connected pipelines which enables a high level of operational flexibility. The result of this facility arrangement is a very complex isolation plan and requires large product drain-up volumes. Secondly, it was a requirement that the replacement piping, which is both larger diameter and heavier walled than the pre-existing piping header, did not increase the stress on any components of the existing piping system during or after installation. Finally, the length and number of connections on the manifold provided fit-up challenges and mandated an extremely high level of accuracy in the fabrication process to remove the requirement for on-site “field-fit” welds which could not be accommodated with the execution schedule. These factors posed numerous structural, mechanical and process challenges for which a detailed discussion is presented to provide insight into, and justification of the design and execution methodologies utilized.

The floating-roof tank has been the most widely used method of storage of volatile petroleum products since the first demonstration b Chicago Bridge & Iron Company (CB&I) in 1923. There have been many changes and design improvements to that first pan-style-floating roof. A floating roof is a complex structure. It must be designed to remain buoyant even when exposed to combined loads from varying process, weather and product conditions. There is a continued demand for improved floating-roof tanks to store a wide range of petroleum and petrochemical products in compliance with state and federal environmental regulations. Floating roofs are used in open top tanks (EFRT), inside tanks with fixed roofs (IFRT), or in tanks that are totally closed where no product evaporative losses are permitted for release to the atmosphere. This very special type of installation is referred to as a zero emission storage tank (ZEST). Products that might have been stored in basic fixed roof tanks must now utilize a floating roof to limit evaporative emissions to the atmosphere. High vapor pressure condensate service and blended heavy crude oils also present new design challenges to the floating roof tank industry. This paper will review the most prominent styles of floating roofs from 1923 to the present. Design and operating limits for current da floating-roof structures are presented. New trends in environmental regulations and the potential impact on the design and operation of floating-roof tanks will be presented. Current maintenance practices and the effect on Life Cycle Cost Management of the storage syste are also reviewed.

In early 1997, Lakehead Pipe Line Company, Inc. (LPL) purchased the Hartsdale Terminal to better serve customers in the Chicago area by providing additional crude oil storage facilities. This terminal is located adjacent to Lakehead’s Griffith, Indiana Terminal and consists of nine crude oil tanks totaling 900,000 barrels of storage capacity. All nine of the Hartsdale tanks were constructed in 1956, are 134 ft. in diameter, and are open top with double deck style floaters. This report describes the integrity analysis of the facility and the corresponding maintenance plan that was developed. The analysis portion of this report describes the inspections that were done on the tanks, covering aspects such as weld spacing; tank settlement; interior and exterior coating failure; tank shell, bottom, and pontoon corrosion; seal wear and performance; roof drain integrity; and other OSHA and API mandates. The resulting maintenance plan is approximately a five-year window and is currently in its first year. The five-year duration was based on issues both operational and financial. A portion of the discussion is focused on the challenge of combining these two components into an overall comprehensive plan. In addition, aspects affecting the maintenance plan such as risk assessment, OSHA and API standards, and budgeting issues are described.

This paper reviews Trans Mountain’s progress in the development of vapour collection and control systems for petroleum storage tanks. These systems are specifically designed for removal of Hydrogen Sulphide (H 2 S) vapours. The basic principles for vapour emission control and the design basis for the vapour control systems are reviewed. Experience with a number of adsorption processes is documented and current development work on an alternative vapour collection systems is presented.

Above ground petroleum product storage tanks are tanks or other containers that are above ground, partially buried, bunkered, or in a subterranean vault. These are built to store petroleum product for pipeline system, oilfield and refinery. Tank fires are one of the most terrible accidents in oil pipeline transportation stations. Tank fires pose a significant hazard to people, buildings, process piping, the environment and other facilities as a result of thermal radiation exposure. It is necessary and meaningful to study the distribution of the thermal radiation of a tank fire for emergency response, prevention and reducing loss. To analyze potential tank fire incidents at a pipeline station, a three-dimensional station model was built using a computational fluid dynamics (Abbreviated as CFD, is a branch of fluid mechanics that uses numerical methods and algorithms to solve and analyze problems that involve fluid flows) software package to evaluate the thermal radiation distribution under different conditions. Numerical simulations were carried out for a total of six simulation scenarios to analyze 3 types of potential fires for 2 different liquid products (gasoline and diesel). The three kinds of fires that were modeled included: 1) disk pool fire on top of the tank; 2) ring pool fire on the top of a tank; and 3) pool fire in a dike. The simulation evaluates the effect of the thermal radiation on facilities and people. The simulation results show that the water cooling system is effective at decreasing the magnitude of thermal radiation exposure and as a result is effective at protecting nearby tanks and facilities. Without water protection, the disk fire or ring fire can destroy or damage nearby structures significantly. The results of the simulation also show that the dike pool fire can have a catastrophic consequence to nearby facilities. Further the analysis showed that environmental wind does not change the thermal radiation distribution significantly. The results of the simulation point out countermeasure activities to enhance fire prevention at oil pipeline transportation stations in a scientific way.

It is difficult to inspect a tank floor when tank is in service. The conventional inspection of a tank floor after it is opened and cleaned is time-consuming and is a high cost. So the in-service inspection of above-ground storage tank floors with Acoustic Emission (AE) technique is accepted by petrochemical industry more and more. Until now more than 70 tanks have been inspected with AE technology in PetroChina Pipeline Company. In this paper our method is introduced and the influencing factors for AE testing are discussed. The reliability of AE testing is mainly concerned by comparing the results of AE testing with the one of conventional nondestructive testing (NDT). The study concluded that the AE inspection is a useful and economic tool for prioritizing the tank maintenance.

Every 20 years hydrocarbon storage tanks are taken out of service for API 653 mandated inspections and repairs. While the tanks are out of service other work is often completed. This paper chronicles the steps taken to ensure all the work is identified, budgeted for, scheduled, and completed in a timely and cost effective manner. This paper assumes the reader has a working knowledge of atmospheric hydrocarbon storage tanks.

Pipeline and storage tank corrosion defect inspection is one of the most important concerns for integrity management of oil & gas storage and transportation industry. Besides the internal inspection for pipeline, tri-axis high-resolution magnetic leakage inspection technique which is applied for trunk line inspection, long range ultrasonic guided wave technique based on Lamb wave is adopted for inaccessible part inspection in technique package for pipeline inspection in PetroChina. Corrosion in the tank floor and wall is a serious threat for environmental and economic safety. Owing to the capabilities of ultrasonic guided wave which are long-range, in-plane propagation, in-service storage tank floor/wall inspection becomes possible by employing an array of SH wave transducers mounting on the edge of the outer storage tank floor. At this point, ultrasonic guided wave shows its capability for pipeline and storage tank corrosion defect inspection. With the advancement of high-performance transducer, its capability will be boosted for even longer and remoter detection. Currently, ultrasonic guided wave system for pipeline could detect defect 200 m away in ideal case while 3∼6 m for storage tank floor in practical case. The complexity of the application of ultrasonic guided wave in tank floor inspection lies in the object containing multiple lap joint welds along the large diameter of the tank (up to 100 m) and the complicated reconstruction of the two-dimensional defect distribution information. The prototype of ultrasonic guided wave system for storage tank is able to detect defects along the edge of storage tank floor. Once the propagation mechanism at overlap joint welds is broken through, the system capability is believed to be greatly improved. The main scope of the paper is to introduce the ultrasonic guided wave principles and the system design of the inspection systems for pipeline and storage tank, respectively, including the system electrical module, hardware program and the module of data acquisition, analysis and processing. Besides, the field application study cases are included to show the capability of both systems and their potential for integrity management in oil & gas storage and transportation field.

Robotic technology is the most advanced quantitative in-service inspection technology for storage tank floor in the word, which can densely scan the tank floor and get thickness of tank floor without opening and cleaning the tank. Compared with the traditional sampling inspection with ultrasonic thickness gauge after opening the tank, in-service robotic inspection is more reliable and efficient. However in some situation robot can’t fully scan the tank floor due to the restriction of the internal structure of tank. Here the extreme value analysis (EVA) method is applied to the data process of robotic tank floor inspection to improve its reliability, and to make this technology adapt to the situation where there are some obstacles and unreached zones on the tank floor. The procedure of EVA is introduced in detail and an example based on field inspection data is demonstrated to verify the benefits of this method.

This paper details the complete four-step Liquid Petroleum - Internal Corrosion Direct Assessment (LP-ICDA) for two operationally different liquid petroleum pipeline systems owned by Kuwait Oil Company. The internal corrosion pipeline wall metal losses were originally predicted using a uniform pitting factor and subsequently upgraded by a dynamic pitting factor. The first case evaluated three, 1959 vintage, non-piggable 40″/38″ telescopic export crude oil pipelines (CR102, CR103 and CR104) with individual corresponding parallel run lengths of 7.7km. All three pipelines run parallel to each other in a common corridor. They are gravity-fed from a storage tank farm resulting in a moderate fluid transit operating velocity. The second assessment was performed on a 6.5 year-old, piggable 36″ crude oil production pipeline (CR088) with an overall distance of 25 kilometers. During the Pre-assessment step, pipeline historical and operational data were collected. Limited historical data was available for the 3 non-piggable pipelines compared to the newer 36″ pipeline which was ultrasonically (UT) inspected via in-line inspection (ILI). In the Indirect Inspection step, the proprietary internal corrosion predictive model (ICPM), enpICDA TM , was applied with a uniform pitting factor to predict the amount of degradation at those locations where liquid hold-up, solids accumulation, and in-turn the internal metal losses would be most pronounced. During the Detailed Examination step, “in-the-ditch” UT was utilized to measure and confirm the remaining wall thicknesses of the three gravity pipelines whereas a comparison of the ICPM to the ILI was executed for the newer 36″ × 25km pipeline. In the Post-Assessment step, a comparison between the predicted metal losses and the UT-ILI measured data were carried out. As a result of a gap analysis, dynamic pitting factors were proposed and developed to enhance and update the proprietary model for predicting the metal losses point-by-point within each subregion over the entire pipeline in terms of local pressure, temperature, water accumulation, and solids deposition. Validation of the in-house prediction was performed using the field measurements for gravity pipelines and ILI data for CR088, demonstrating that metal losses predicted by the proprietary model and measured through field tests and ILI data agree reasonably well for both extreme scenarios. Results showed that three gravity pipelines have minimal internal corrosion under a high flow velocity despite having a 51-year operating history whereas severe internal corrosion was identified after a 6.5-year operation for the CR088 pipeline. Hence, selection of a proper operating velocity is crucial for crude oil pipeline operations. Under a low speed condition, localized pitting corrosion dominates whereas uniform corrosion is predominant under a higher flow or “sweep” velocity. Since the pipeline operators were more interested in the worst-case scenarios, i.e. metal loss due to localized pitting corrosion, development of dynamic pitting factors was undoubtedly an innovative improvement of the overall Liquid Petroleum - Internal Corrosion Direct Assessment through capturing the fluctuation of metal losses along the entire pipeline, which can enhance the ICDA methodology toward a higher level of precision and accuracy.

Large storage tanks for oil storage are widely used in petrochemical industry. Corrosion in the tank floor and wall is a serious threat for environmental and economic safety. Owing to their unique potential for long-range, in-plane propagation through plates, Ultrasonic Guided Waves (UGW) offer an obvious solution in the development of an on-board structural health-monitoring (SHM) system, providing assessment of structural integrity for storage tank floor and wall defect in-situ inspection. This paper presents this application by focusing on their propagation through the plate structure. Even very small mechanical discontinuity or geometry change of plate structure, e.g. corrosion defect on tank floor, will influence the propagation characteristic of the guided waves. These effects are measured as mode changes, frequency shifts or filtering, reflection and diffraction of new ultrasonic modes or overall distortion of the original ultrasonic signals. By capturing and analyzing these changes we can deduct the corrosion defect of the tank floor and wall which causes the ultrasonic signal change and interactions. The T/R transducers are required to be attached on the outer edge of the tank floor and outer surface of the tank wall. The technique is developed based on the Lamb wave transmission tomography. Starting from the dispersion curve and choosing the appropriate wave mode, the propagation of the guided waves in the tank floor and wall has been carried out through numerical simulation and the experiment has been conducted for verification using the full-size oil storage tank. The low frequency guided waves can propagate longer distance in planar and tubular structures. The later has been already used in pipeline inspection. The complexity of the application of ultrasonic guided wave in tank floor inspection lies in the object containing multiple lap joint welds along the large diameter of the tank (up to 100 m) and the complicated reconstruction of the two-dimensional defect distribution information. The main scope of the investigation was the application of the ultrasonic transmission tomography for localization of non-uniformities of inside tank floor, taking into account ultrasonic signal losses due to the loading with oil on the top and ground support at the bottom for the tank floor, and the loading with oil inside for the vertical tank wall.

Much manpower is needed and a lot of materials are wasted when the floor of large above-ground storage tank (AST) is inspected with conventional methods which need to shut down the tank, then to empty and clean it before inspection. Due to the disadvantages of that, an in-service inspection method using acoustic emission (AE) technology is presented. By this mean the rational inspection plan and integrity evaluation of tank floors can be constructed. First, specific inspection steps are established based on the acoustic emission principle for large AST’s floors and the practical condition of AST in order to acquire the AE corrosion data. Second, analysis method of acoustic emission dataset is studied. Finally, maintenance proposes are provided based on results of analysis for the corrosion status of the tank floors. In order to evaluate the performance of our method, an in-service field inspection is practiced on product oil tank with a volume of 5000 cubic meters. Then a traditional inspection procedure using magnetic flux leakage (MFL) technology is followed up. Comparative analysis of the results of the two inspection methods shows that there is consistency in localizing the position of corrosion between them. The feasibility of inservice inspection of AST’s floors with AE is demonstrated.

As an important production facility, storage tank plays a more and more important role in the storage and transportation of crude oil and chemical product. The remaining life prediction of storage tank is to forecast the thinning trend of plate thickness, and forecast remaining life on the premise that remaining strength of storage tank meets the tank operation and safety requirements. Maximum corrosion depths of tank bottom plate obey the maximum extreme value distribution. Based on maximum extreme value distribution and statistics of corrosion data, the calculation formula of the remaining life prediction for large-scale crude oil storage tank was obtained by formula derivation. Compared with API STD 653 and EEMUA 159, the inspection interval specified by China standard SY/T 5921 is relatively conservative. The remaining life of a certain crude oil storage tank (tank A) in china is determined by the remaining life of tank bottom plate. The remaining life of tank A at the reliability of 0.99, 0.999 and 0.9999 are 25 years, 20 years and 17 years, respectively. For the acceptable failure probability of 1×10 −4 , the inspection interval of tank A can be extended from required 5–7 years specified by China standard SY/T 5921 to 17 years. The remaining life of crude oil storage tank predicted by the method proposed in this paper can be used as an important reference in the determination of inspection interval and tank’s maintenance.

Oil storage tanks are crucial components in the petrochemical industry for transportation and storage. Corrosion of the tank floor and vertical walls is one of the most important safety concerns. In-situ inspection of the tank floor and walls with ultrasonic guided wave technique by edge- and wall-mounted transducers is still an active research area nowadays. A great deal of research has been conducted in detecting the defect of plate-like structures using Lamb waves. This application has been motivated by the fact that the Lamb wave velocity is the function of frequency and structural geometry (thickness), also the Lamb waves can propagate with low attenuation for long distance in plate structure. However, the complexity due to the existence of multiple Lamb wave modes weakens its applicability. Lamb waves are typically excited by transducers mounted on the surface of the inspected plates. Higher order modes are generated if the frequency-thickness product exceeds a certain threshold value that is dependent on the material of the plates. Low frequency guided waves can reduce this complication as only a small number of wave modes are generated. So operation with low frequency guided waves is usually recommended, but it encounters a problem that the resolution gets degraded hence small defects (compared to the wavelength) are difficult to detect. Our investigation considers the generation of guided waves in tank floor and vertical wall by edge excitation and wall-mounted excitation, respectively. Only when there is no access to the edge of the vertical wall, the wall-mounted excitation (surface excitation) is used. When the frequency-thickness product is small Lamb waves are generated, otherwise, longitudinal waves are generated. We investigate the intermediate frequency-thickness products where a pulse train of semi-longitudinal waves is excited. The pulse train is comprised of a leading pulse and some railing pulses, which have been predicted by the acoustic theory. The transition from Lamb wave to semi-longitudinal wave is investigated. In addition, energy transport from leading pulse to trailing pulses and the interaction of these trailing pulses with defects are studied. The results revealed that the semi-longitudinal wave is a viable option for tank floor and wall defect inspection.

Enbridge Pipelines Inc. utilizes aboveground crude oil storage tanks for operational flexibility and merchant storage purposes. Most of these tanks are built in accordance with the requirements of API 650. This standard requires that an appropriate corrosion allowance be included in the minimum shell thickness calculations. A variety of sources were researched in an effort to develop a process that ensures the selected corrosion allowance allows for the safe operation of a tank for its entire service life. Some of these sources include other API standards, historical API 653 tank inspection reports, published atmospheric corrosion rates, and corrosion allowance specifications of industrial counterparts. Defining an appropriate corrosion allowance requires consideration of a number of factors: • Whether or not the product contains significant sediments and water; • Whether or not an internal lining will be applied in accordance with API 652; • The length of time to the first out-of-service inspection; • Whether or not the tank will be externally coated; • The temperature of the product stored; • The annual precipitation at the specified location; • The average chloride concentration in rainwater at the specified location. During the course of the corrosion allowance study, the issue of maximum allowable design stress was also considered. The allowable stress values specified in the standard for construction of new tanks (API 650) differs from the allowable stress values specified in the inspection standard for existing tanks (API 653). It has been suggested that the incremental difference between the minimum shell thicknesses calculated using API 650 instead of API 653 could be designated as corrosion allowance. This paper will describe the corrosion allowance calculations in detail as well as address the issue of maximum allowable design stress.

The last revision of the American Petroleum Institute (API) guideline for the inspection of facility piping (API 570) includes tracer leak detection methods as an alternative to hydrostatic testing of buried pipelines. Tracer testing is a method in which a small concentration of a chemical label is added to the fluid inside a pipe. If a leak is present, analysis of air samples collected outside of the pipeline shows an increase in the concentration of the chemical vapor above background. Tracer test methods have been evaluated and validated by many studies. A summary of the cumulative data is described. Cumulatively, two hundred and one leaks were simulated under a variety of conditions. All but one of the leaks was detected. Of the one hundred and one control events in which no leak-indicating tracer was released, there was one false indication of the presence of the tracer. The autopsy of this event revealed that the false detection was due to operator error. Individual leaks have been located in large diameter pipelines regulated by the United Sates Department of Transportation. A case study is summarized in which a single leak in a forty-kilometer section of 0.4-meter diameter piping was located. This was a newly constructed yet to be commissioned pipeline built for the transport of natural gas. The single leak was located during the first day of sampling. Large refineries have used tracer methods to meet regulatory or facility inspection requirements. Refineries and chemical plants have used developing and established tracer test methods to meet regulatory requirements and to explore new ways of augmenting Asset Integrity Management programs. A six-year tightness testing program for a refinery/chemical plant facility including fifty kilometers of facility piping is summarized. During the most recent test season at the chemical plant, the frequency of detection of small leaks was one leak per kilometer of piping. None of the leaks detected during the six-year project accounted for the amount of petroleum product below ground surface. Significant releases at this facility were attributed to aboveground storage tanks. A final case study is included in which the location of a leak in an operating refinery pipeline and an associated aboveground tanks is summarized. The leak detection and location project was combined with a field evaluation of a new leak detection method for operating pipelines in which below-ground leaks are detected in samples collected above the ground. The leak in the supply line was located within the first twenty-four hours after the addition of the leak indicting tracer. Another leak through the floor of an associated aboveground storage tank was also detected on the day after the tracer was added by the presence of the leak detection tracer additive in samples collected below the tank. The tank also remained in continuous operation. Advantages of the test include: continuous operation of the piping and tanks during the test, avoidance any need to remove product, replace the product with water, treat the contaminated water or dispose of it. The use of a chemical tracer test method, designed for operating facility tanks and piping can in many instances serve well as an alternative to hydrostatic testing for meeting API 570 standards.