ABSTRACT Due to the constant need of improving flow, pressure and pipeline throughput for single phase flow in fluid pipelines and due to extensive injection of DRA into pipeline networks, whether to supply an increased demand of customers or uprate an overall throughput of a pipeline system, a need to find ways to optimize the effect of DRA injection on the flow rate and pressure has become essential in the pipeline industry. This study looked into the effect of drag reducing agents on the flow rate and pressure of single phase flow in fluid pipelines. Reviewing the literature helped a lot in planning a methodology that explains how the investigation is carried. The methodology started with selecting a pipeline network to be case studied and then utilizing an advance tool that can perform hydraulic pipeline calculations to simulate various cases. After that, results are evaluated, analyzed, and discussed to make sure that they match with the obtained current pipeline data. To optimize, a hydraulic simulation tool called SPS is used to simulate cases where effect of DRA on the flow rate and pressure is improved. Having gone through several investigations on how to optimize the effect of DRA on the flow rate and pressure of single phase fluid pipelines, a number of recommendations has been made to modify several factors that eventually lead to optimization of the effect of DRA. Initially, the definition and characteristics of DRAs has been made clear and understood to be able to know more about what is being researched and investigated. Additionally, the mechanics behind drag reduction have been understood and the effect of DRAs on the flow rate and pressure of pipelines once injected has been understood. Factors such as location of DRA injection, DRA type vs. %Dr, and DRA concentration have been proven to be effective in optimizing the effect of DRA based on the results of the simulated cases. Savings reaching up to $4 Million on spending for one type of polymeric DRA injection were the results of only one factor contributing to optimization which was the location of DRA injection.

ABSTRACT One of the urgent and time-consuming problems in the area of oil and oil products transportation is the problem of oil cargo flows scheduling in trunk pipeline systems. The problem is complicated by the necessity to take into account both the characteristics of the oil pipelines themselves, the properties of oil and capacity of tank terminals. The relevance of this topic is due to the deterioration in the composition and properties of incoming oil to the pipeline systems from suppliers, the increase in the share of high-sulfur oils and the need to supply low-sulfur oil to consumers. The article considers a new approach to oil transportation scheduling in branched oil pipeline systems. A new approach based on mathematical model that solves the optimization transport problem. The transport problem is formalized as a system of objective function and constraints then this system is solved using linear and sequential quadratic programming methods. The system can be varied depending on the needs of a given pipeline system. The approach allows to compute oil flow distribution during the certain time period (day, week, month, etc.) with given time sampling (hour, day, week, etc.) considering pipeline characteristics (flow capacity, technological regimes, etc.), oil properties (mass sulfur fraction, density, etc.) and capacity of tank terminals. Also, the approach allows to optimize oil transportation by energy consumption. The possibilities of the proposed approach are shown using a system of 10 oil pipelines, 4 transitional tank terminals, 3 oil suppliers and 6 oil consumers. The result of flow distribution calculation in a branched system is the schedule of cargo flows for each pipeline in a whole pipeline system with all constraints satisfied and optimized objective function.

ABSTRACT The Austin-Palfrey equation could be directly applied to a pipeline where both the Reynolds number and the pipe diameter are not varied along the entire length and where there is no initial mixing volume at the start point of the pipeline. If the Reynolds number, or the pipe diameter, or both are varied along a pipeline, the pipeline should be divided into segments based on the point along the pipeline where Reynolds number or the diameter change. The Austin-Palfrey equation should be revised to include effects of the initial mixing volumes in subsequent segments. In this study, the Austin-Palfrey equations were revised by introducing an initial pipe length or an initial length factor to incorporate the initial mixing volumes at the start point of each pipe segment. The revised equations could predict the mixing volume along the entire pipeline length. The initial length factor has an impact on the incremental mixing length in subsequent segments. When the initial length factor is larger than one, the mixing length in subsequent pipe segment tends to decrease. When the initial length factor is less than one, the mixing length in subsequent pipe segment tends to increase.

ABSTRACT One of the most important aspects when transporting multiple different liquid products within the same pipeline, is being able to know where the head and tail of each batch is at any given time based on the current operation to provide an accurate Estimated Time of Arrival (ETA) at upcoming stations. With this information, pipeline operators can be ready to execute valve swings at intermediate delivery and injecting stations helping minimize product contamination. It is relatively simple to track these batches and their interfaces when the pipeline has a uniform and gradual elevation profile. However, when pipelines travel through mountainous regions with high and drastic elevation changes, the ability to track the head and tail of these batches become far more complex due to the presence of slack. When slack is present, the common assumption that the volume of liquid equals the physical volume of the pipe is no longer valid. The fraction of the pipe filled with liquid, called the "liquid holdup", has a large impact on the position of the batch head and tail. As a result, the accuracy of the volume contained within the region and the corresponding Estimated Times of Arrival at upcoming stations are directly affected. An empirical approach using volume accumulation at a pipeline injections and deliveries has been successfully implemented with an end user to account for the liquid volume within a specific region known to have slack during normal operations. However, this approach does not provide an accurate solution for the exact location of where the slack occurs, nor the size of the slack itself, which has a direct effect on the location estimate for when the head or tail is passing through the area. With the current empirical approach, Estimated and Actual Times of Arrival are within a 15-minute time window after a batch has traveled a total distance of 1,200 km (746 mile) with a drastic slack region along the route. This paper provides an analysis on the current empirical approach used in the daily operation by the existing end user, and how the results compared to a full scientific approach running a slack model based on the field instrumentation, and the physical properties of the pipeline.

ABSTRACT It is a challenge to simulate the surge relief valve behavior accurately and handle the "minor frictional losses" from the pipe fittings in the terminal transient analysis. Some hydraulic engineers model the surge relief valve with the assumption that it will perform as ideal default behavior, and proposed relief set points based on the ideal default behavior may not prevent the maximum surge pressures from exceeding 110% maximum operating pressure (MOP) of terminal piping in real-world operations. Furthermore, aggressive relief settings will limit the mainline's capacity. On the other hand, over-conservative relief settings will cause nuisance pipeline start-up failure and relief shutdown events. A terminal hydraulic study was performed, which included both steady-state and transient analyses. Steady-state simulation is applied to determine the terminal system design, while transient simulation is used to assess the surge potential in the piping system to prevent the pressure dynamics from exceeding 110% of the maximum allowable operating pressure. A mainline pump trip scenario in the terminal is usually the most severe surge event; therefore, a surge relief system is typically installed at the pump's suction side (the pressure specification break point) to protect the lower pressure rated terminal piping from an over-pressure condition after the pump station trip. This paper discusses the use of an advanced simulation method to successfully match the real suction surge pressure trends for the worst-case terminal transient scenario: the mainline pump station trip accompanied by a surge relief event. The methodology includes arithmetically coding dynamic relief set points and applications of equivalent length in the terminal transient study.

ABSTRACT Presently one of the methods of increasing pipeline capacity is using the drag reducing agents (DRA). DRA are typically high molecular mass polymers that are added at very low concentrations to reduce the pressure drop necessary to generate a given flow rate in a turbulent flow. They can be used in case if building of extra loops or pumping stations is impossible or the need to increase pipeline capacity is seasonal. Scheduling pumping regimes and calculating the amount of drag reducing additive necessary to achieve the specified pumping parameters, requires a mathematical model. This paper proposes a method that allows to integrate DRA into a mathematical model of viscous fluid motion in a pipeline. The model takes into account the degradation of DRA as the agents travel forward the pipeline. This article focuses on the question of theoretical model adjustment to the characteristics of a certain pipeline. Using the nominal information about DRA (provided by manufacturers) generally leads to a strong error and some information needed for the modeling might not be provided at all. Thus, the model needs to be tuned to the real DRA characteristics and the main source of data are real measurements of flow parameters (pressures, flow rates, etc.). Methods of using operational pipeline data for identifying DRA characteristics are considered. The issues of data collection and further data processing are discussed. The results of comparing modeling computations with real data from operating pipelines are presented. The characteristics of these pipelines are very diverse: internal diameters vary from 0.4 m to 1 m, different DRAs are used, and different types of liquid (oils, oil products and gas-condensates) are pumped.

ABSTRACT Economically optimizing DRA within a crude pipeline is simple when using an optimization program, however it is challenging and important to understand how the optimization works. This paper will address a methodology of how DRA and power are optimized to minimize economic costs. Then an analysis will look into how velocity, fluid viscosity, DRA performance, pump spacing, pipe size, cost of electricity, and cost of DRA affect economic optimization results. Finally, this paper discusses several key factors that affect decisions such as building new stations or laying new pipelines versus increasing DRA injection rates into existing assets. APPROACH Energy is consumed in order to move a barrel of oil. DRA decreases the amount of energy that is required to move that barrel of oil. A price associated with both energy consumption to transport a barrel of oil and DRA utilized to reduce the energy consumption. The goal of optimizing DRA usage is to minimize the total cost to move each barrel of oil from origination to destination.

ABSTRACT Heavy oil accounts for more than half the word's total oil reserves. However, heavy oil as extracted from the reservoir has an extremely high viscosity and the transportation of these fluids in a pipeline requires the use of technologies to lower the viscosities of this oil. Among these technologies are heating or dilution of the heavy oil and sometimes a mixture of both of these methods. The majority of oil storage terminals contain pipes that are installed above ground and in northern countries are prone to experiencing cold temperatures during winter months. In part of the terminal where the fluid stays stagnant in the pipes (such as relief piping and manifold pipes) the cold weather can impact the viscosity of the fluid, even after it has been diluted. When the pumping system has to move fluid that has been stagnant in the pipe and has become colder, the pressure required to achieve this is very high. The transient surge pressures created in these cases can become extreme to the point of exceeding the maximum operating pressures of the pipe. When performing transient simulations, it is important to consider the fluid with higher viscosities that have been kept in the pipes and that will require higher pressures to pump them down the line, so that pressure surges can be more accurately calculated and mitigated. This paper will present comparisons of how the transient pressures change between cases of heavy oils at different temperatures and viscosities. It will show that if heavy oil is kept stagnant in a pipe that is subject to cold temperatures, the pressures required to push this fluid down the pipe increases as the viscosity becomes higher. IN particular, it will present the case where the relief piping has been installed above ground and when the fluid needs to be displaced, the surge pressures can become significantly higher than expected.

ABSTRACT LNG Terminals represent key infrastructure for gas markets in many regions. With markets shifting to a more global approach, what happens when your operational cases evolve, and the original design specifications are challenged? Or worse an operational event exposes weakness in the design? The priorities on any site continue to be around safe, profitable operation and maximising capacity/uptime. Under normal operation piping systems can withstand the resulting stresses. Events such as rapid PERC (powered emergency release coupling) closures, Emergency Shut Downs (ESDs), valve operations, and pump trips can all create transient effects. Consequences can include excessive surge pressures which in turn lead to increased pipe stresses and structural loads. An ongoing relationship with a large LNG terminal operator has driven studies into hydraulic surge in pipelines following Emergency Shut Down (ESD) events and developed this hydraulic understanding to include bend forces and resolved pipe forces which could be passed into targeted structural analysis. Over time, scenarios have become more complex including for example an increasing need to be able to re-load ships from a site originally designed as an import terminal. Alongside the technical challenge of these studies; a key factor was generating justifiable rationalisation of all permutations of operating scenarios into a manageable quantity of worst-case simulations for a multi-tank and multi-jetty site. Combined with the increasing complexity of cases we were required to develop methods to run simultaneous simulations and manage the model files and outputs in a reliable fashion. More recent work has led to feeding the force outputs into static and dynamic load analysis to understand the force and harmonic interactions with the physical structures on the site. Pressure and force results were extracted for each scenario using a high-fidelity hydraulic model and then utilized in structural analysis tools for further analysis. This paper outlines the evolution of a complex modelling problem, and the effects of working on an inherited model from a 3rd party and architecture built on scripting tools to solve problems now integrated into our modelling solution. With the concept of simultaneous modelling runs and parametric studies commonplace in today's environments, we consider the progression of this approach to meet future requirements.

ABSTRACT A novel model is used to predict the inception moment and location of a phenomenon known as the column separation or slack line. The existing models for prediction of the cavitation phenomenon in internal flow systems in general are primarily formulated for the capture of the inception moment and initial location of the event only. Hence questions such as where the incepted cavities and bubbles tend to go, or the detailed state of a slack line in time should be addressed using a different approach. The model presented in this paper is validated and verified against experimental data available in the literature before being applied to a 53 Km (33 miles) industrial pipeline. Imposing conditions at the injection and delivery ends of the line tests various scenarios causing column separation. Hydraulic parameters such as pressure head and flowrate as well as interfacial mass transfer rate of the incepting and collapsing bubbles and cavity zones are predicted in real time over the entire domain of space and time. The results predicted the fate of the separated column of the fluid, whether they rejoin or continue to change the size with different rates or even if they become stabilized stationary cavity pockets after passage of minutes or hours. Results are also compared based on the initial cause of the column separation such as huge transients. Also, accurate prediction of the whole column separation event, distinguishes it from other events, which would commonly mimic or mask the column separation by exhibiting identical hydraulic footprints.

ABSTRACT Upstream gas supply planning and allocation contains 3 cycles namely long term (20 years - end of life of a field) mid-term (up to 1 year) and short term (72 hours). Since the upstream assets are owned/operated by different companies under various production sharing contracts, each of the operating companies prefer to maximize their production and recover the investment costs at the earliest. A regulator acts as a custodian to ensure that all stakeholder's entitlements are protected. The custodian relies on economic and hydraulic modelling to analyse the production plateau's shared by various operating companies together with the demand profiles for viability. The commercial planning team of the custodian works closely with flow assurance engineers before confirming the production numbers as the planners are unaware of any capacity constraints in the physical network for flow. In the short term, an integrated network operator breaks the long term demand numbers and controls the network for seamless delivery of gas from upstream to LNG plants (mostly). The purpose of the paper is to highlight the challenges faced by planners and engineers during the planning cycles and to make appropriate recommendations.

ABSTRACT The Mexican Energy Regulatory Commission, Comisión Reguladora de Energía (CRE), has recently approved the use of new short-term service agreements. The need for the agreements within the national gas pipeline system (SNG) was triggered by the development of pipeline infrastructure and is described in the national infrastructure plan developed by the Energy Ministry, Secretaría de Energía (SENER). The Mexican National Center for Natural Gas Control, CENAGAS, required a mechanism to include the new agreements in pipeline simulations. This paper explains the pipeline simulation techniques being implemented to model the new agreements. The steady-state and transient simulation offers justification for the construction of new facilities; and establishes the operating requirements of new interconnections and the installation or reconfiguration of compressor stations. The paper also discusses how CENAGAS incorporates the pipeline simulation techniques for short-term service agreements into the existing capacity determination processes. The paper also verifies the parameters and assumptions that CENAGAS has determined are important for pipeline simulation of the new short-term service agreements. Notes: National Gas Pipeline System (SNG): The Transport and Storage Unit (UTA) of CENAGAS is responsible for the operation and maintenance of approximately 87 pipelines of 4" to 48" inches diameter, with a length of 5348 miles (8610 kilometers) and a capacity of more than 5 BCFD, of pipeline extending from the Sonora, Nuevo León and Tamaulipas border to the Paso/Texas border with connections to other natural gas pipelines in the U.S. National infrastructure Plan: This document establishes that in the period 2017-2031 a decrease in national natural gas production is observed, which leads to an increase in the importation of natural gas, Imports into 2031 could reach 4.6 BCFD, in a scenario in that all imports would be transported by pipelines (without considering the imports of LNG), as a result of the development of the new gas pipeline infrastructure. This volume would represent 48% of the national gas supply.

ABSTRACT In the design and operation stages of multiphase pipelines, prediction of flow temperatures and pressure variations is important. Dynamic evaluation of process changes in real-time and calculation of thermodynamic properties of multi-component mixtures is challenging. In this paper a mechanism to counter phase change losses due incorporating real-time dynamics is presented. A case-study for a major oil and gas distribution company with real-world deployment and observation has been included. The model provides notification of changes and displays a PT-phase diagram using different gas compositions and oil assay data to compare the phase changes in model and commercial pipelines in real-time. With density and viscosity considerations in the approach, gas condensation alarms are raised dynamically depending on the total vapor fraction in the mixture.

ABSTRACT This paper provides an overview of Pacific Gas and Electric Company's (PG&E) In-Line Inspection (ILI) process from start to finish. PG&E's integrity management program encounters numerous operational challenges as it expands its in-line inspection program to include more challenging pipelines than previously inspected. The company has addressed these challenges by developing a rigorous hydraulic feasibility study process that evaluates risks associated with a respective ILI run before making the decision to proceed with pipeline retrofits to accommodate in-line inspection tools. Several new operating methods have been developed to increase the number of pipelines hydraulically capable of in-line inspections, while reducing risk. Two tools that PG&E has developed to analyze ILI system operations will be discussed. PG&E's Batch Analysis Tool (BAT) is used to conduct complex, multiple-scenario hydraulic analysis. Data results are then processed through an ILI BAT Results Tool, which summarizes BAT data into easily-viewed charts and tables. This allows engineers to consistently analyze and document predicted ILI run gas velocities and system response to varying operations during the inspection. Once detailed analysis is conducted, preparation for the ILI is required. This paper will discuss upgrading pipelines to accommodate inspection tools, developing detailed operating plans, directing real-time operations, and preparing to respond to operational impacts due to anomalies identified on the line. A case study of an ILI on Distribution Feeder Main (DFM) 0617-06 is presented to exemplify PG&E's ILI process from start to finish.

ABSTRACT This paper defines and studies a simple, efficient method for discretizing pipeline equations in time. In many ways the solutions of pipe flow equations look like the solutions of nonlinear diffusion equations, so it is natural that schemes that work well for diffusion problems might have analogs for pipe flow problems. The method presented here is based on backward Euler (BE). To advance the solution from time t to time t+dt it uses a single step of BE with step size dt and two steps of BE with step size ????/2. The results are then combined to give a second-order correct scheme. This process is called step doubling with local extrapolation (SDoLE) and has been rigorously analyzed for nonlinear diffusion problems in the context of Galerkin spatial discretizations. [1] Here a collocation scheme is the underlying discretization in space and time. The backward Euler that forms the basis of this method is done using a linearization technique instead of solving a nonlinear system. This is extended to minimize the computational costs associated with evaluation of the nonlinearities in the equations. The resulting discretization technique is called affine step doubling with local extrapolation (ASDoLE). The properties of the method are explained by looking first at a scalar ODE and then by presenting examples based on pipeline operation. A single pipe case is given followed by a simple gun barrel example.

ABSTRACT We present an algorithm that dynamically reorders the evaluations in a parametric study to find the "interesting" areas sooner rather than later. In some circumstances it can be much faster than traditional studies. Reduced time means faster turnaround for studies, shorter decision cycles, and allows a higher number of dimensions than would normally be considered. We give a simple explanation of the method and present some specific use cases on existing pipelines. We believe this algorithm will be useful for broad categories of problems in pipeline (and other) industries.

ABSTRACT Analysis of the operating risk due to hazardous liquid pipeline spills is a challenging task. One reason for this is the fact that the spill probability and the magnitude of the release are both difficult to quantify for any particular pipeline. One source of comprehensive information regarding spills in the United States is the Department of Transportation (DOT) Pipeline and Hazardous Materials Safety Administration (PHMSA) hazardous incident database. This database is a mandatory compendium of spill incidents dating from 1968, and relies on self-reporting on the part of pipeline operators. We use this database to calculate historical average spill incident rates for various designated spill causes, and demonstrate a methodology using a tail risk analysis of the limited release orifice information supplied by the database to calculate a more complete aperture probability distribution for those causes. The incident rates developed by this analysis are then adapted to obtain more reliable incident rates for a particular pipeline by using the PHMSA results as a prior estimate and implementing a Bayesian posterior update based on historical sparse spill information for that system. We conclude by showing how the information obtained can be used in conjunction with pipeline hydraulic, leak detection performance, logistic response, and other models to perform a probabilistic cost-based risk analysis for the pipeline system.

ABSTRACT An important variable considered in the sizing and design of pipelines is the absolute roughness of the pipe, which is used to calculate the pressure loss during fluid flow through the pipeline. The default value for absolute roughness of commercial steel pipe, as generally used in the industry, is 1800 micro-inch (or 46 micro-metre). This value appears to have originated from studies carried out by scientists such as Pigott, Colebrook, Moody and Nikuradse, among others, more than half a century ago. However, pipe manufacturing and treatment methods have become more advanced since these studies were performed. Indeed, recent studies have suggested overestimation of the pressure drop across a pipeline during design resulting in less accurate cost estimates for pipeline projects. In this study, the absolute roughness of various pipeline samples was measured using a Mitutoyo SJ-201 surface roughness gauge. The samples were obtained from commercial steel pipes of different diameters that had been manufactured with various methods including: seamless hot-rolling, cold-drawing, cold pilgering, hot expanding, and welded HFIW and DSAW processes. Absolute roughness values were also obtained for pipes treated differently by: simulated post-weld heat treatments, sandblasting, and ultrasonic cleaning. Recorded average pipe roughness values ranged from 57 micro-inch for stainless steel pipe to 1034 micro-inch for heat treated carbon steel pipe. All measured values were less than the generally used 1800 micro-inch (or 46 micro-metre) value. There did not appear to be any correlation between the diameter of the pipe sample and the absolute roughness observed. The pipes that were manufactured using the hot-rolled method typically showed higher absolute roughness values. Furthermore, simulated post-weld heat treatments at higher temperatures correlated with higher absolute roughness values for heat treated pipe. This paper also examined the impact of applying a range of measured absolute roughness values during the design of liquid and gas pipelines. The pipeline pressure loss was calculated using different roughness values for case studies involving multiple crude oil pipelines and a natural gas pipeline. The results indicated that gas pipelines are more sensitive to the absolute roughness value. Furthermore, liquid pipelines with relatively high Reynolds number are more likely to undergo noticeable capacity loss because of absolute roughness increases due to pipe degradation.

ABSTRACT The Negative Pressure Wave (NPW) leak detection method has been increasing in popularity recently due to the promise of highly accurate leak location calculations compounded with response times on the order of seconds. Additionally, when compared to other leak detection methods such as Real Time Transient Models (RTTM), NPW can be implemented on many different pipelines in a relatively short period of time with only the need for pressure transmitters. However, as with all engineering applications, there are tradeoffs to consider. In this analysis, a NPW solution was evaluated on two different liquid pipelines running offline simulators: one pipeline transports crude oil and one pipeline transports diesel. It was observed that, under very specific operating and test conditions, NPW could perform adequately. The conditions which allow for accurate NPW performance are limited when considering real world operations. With this consideration, NPW can be a complimentary method to other leak detection methodologies. This analysis is intended to provide pipeline operating companies with a greater understanding of when and where an NPW solution may be appropriate, as well as the limitations and challenges associated with the NPW methodology.

ABSTRACT A risk assessment for a new pipeline system is an authority requirement. The risk assessment for a new pipeline system is based on several assumptions and parameters for planned design and operation and is in most cases conservative due to uncertainty in actual conditions. During the lifetime of a pipeline systems these parameters are likely to change, and consequently the risk assessment is no longer representative for the actual operational risk level. Authority requirements also states that a new risk assessment shall be performed when significant assumptions change. In-depth knowledge of risk calculations, pipeline simulations and assumptions are a prerequisite to be able to evaluate whether a change is significant with regards to risk level. The pipeline risk assessment must be well known by the operator to ensure solid risk management for a pipeline in operation. This implies knowledge of uncertainty in assumptions, condition of integrity, operational parameters, environmental data and how these parameters will affect the risk level in certain areas. This paper will discuss the uncertainty of different assumptions and parameters and how they affect the operational risk level for oil/condensate pipeline systems. The focus in this work has been to create a standardized cross-discipline work process to increase operational knowledge of risk factors and decrease the level of uncertainty in assumptions and input data. A combination of data sources and simulation tool are used to calculate a representative pipeline risk level, which will give the operator a solid basis for continuous risk management, decision support and emergency preparedness planning.