Abstract Both in Europe and in North America, the goal to use increasing amounts of renewable energy has created the need for electricity storage. One concept which aims to address this need is to produce hydrogen from surplus electricity, and to use the existing natural gas pipeline system to transport and store said hydrogen. Generally, the hydrogen content in the pipeline flow would be below 20%, thus avoiding the problems of transporting and burning pure hydrogen. The thermodynamic properties of hydrogen-natural gas mixtures, as well as their impact on the combustion process are briefly addressed. To assess the impact of hydrogen addition in various concentrations to a natural gas pipeline, a realistic pipeline system is simulated. The pipeline hydraulic simulation provides the necessary operating conditions for the gas compressors and the gas turbines that drive these compressors. The impact on transportation efficiency in terms of energy consumption as well as the impact on the transport capacity of a pipeline where the equipment was sized originally for natural gas transport, are assessed. Introduction and Background The increased use of renewable energy will require the capability to store energy to balance the large fluctuations in the availability of renewable energy, thus balancing supply and demand. Generating green Hydrogen from surplus electricity using electrolysis and transporting this hydrogen together with natural gas in gas pipelines is a method to provide storage and transportation for hydrogen [1,2,3]. Mixing hydrogen into natural gas pipelines requires a number of considerations regarding the compression of this mixture, the use of the mixture as a fuel for the gas turbines that drive the pipeline compressors, and the impact of pipeline capacity and transport efficiency. There are a number of other concerns, including safety concerns for gas compressor packages, and material issues related to hydrogen embrittlement on rotating parts like impellers, pressure containing vessels (like compressor bodies), and high-pressure pipes. [4].

Abstract The integration of Renewable Energy Sources (RES) into the electric power system and the demand for efficient, clean and reliable production, transport and distribution of energy is connected with an increased coupling between the individual energy systems. The interdependency between natural gas and electric power systems, for instance, is increasing and expected to increase further in the near future, mainly due to the growing demand for flexible backup generation and the need for short- and long-term energy storage options to balance the fluctuations of variable and intermittent RES. The need for flexible backup power can be covered by Gas Fired Power Plants, while the demand for seasonal storage can be met by Power-To-Gas facilities. In this paper, we show how curtailment of RES can be reduced by operating Power-To-Gas facilities. Introduction To meet future decarbonization targets power system planners and operators have to integrate more variable renewable energy sources into their electric power systems. The stable and reliable operation of the power system, however, requires a balance between power generation and demand, since electric energy cannot be efficiently and economically stored in existing power system networks. Due to the uncertainty and variability in the generation from Renewable Energy Sources (RES) and at the same time the lack of energy storage, power system planners and operators must find new flexibility and storage options, which typically lie at the interface between different energy networks, such as natural gas, heat & power networks. Natural gas networks, for instance, have relatively large energy storage capacities (linepack, underground gas storage, LNG storage tanks), which can be leveraged by electricity networks to tackle the flexibility and energy storage challenges. The connection between the gas and electric power system can exist at Gas-To-Power plants (G2P) as Gas fired Power Plants (GPP), electric driven gas compressor stations (Power-To-Pressure - P2P) as well as Power-To-Gas facilities (P2G). G2P facilities have relatively short start-up and shut-down times, making them well suited as back-up generation sources in case of lack of wind and solar generation. P2G facilities, on the other hand, can be used to convert excess power generation from renewable sources into hydrogen (H2) and/or synthetic natural gas (SNG), which in turn can be injected into the natural gas pipeline network and/or underground gas storage reservoirs.

Abstract This tutorial presentation will build on the introductory pulsation topics by expanding the basic theory into advanced topics in gas piping systems. Topics in this tutorial will address complex problems that many operators face today including: wet gas compression and pulsation bottle design, the impact of changing gas compositions for reverse direction flow on pulsations and horsepower requirements, adding pulsation control for integral (Enbloc) compressors, and mixed compression with different unit types sharing a common header. Each topic will be presented with an overview of the subject, case studies and mitigation techniques or analysis methodologies. In addition, an overview of the latest research and development for novel pulsation attenuation methods will be presented as well as the level of technology development for each concept. Introduction and Background Pulsations in piping systems can be generated by reciprocating compressors, centrifugal compressors, flow-induced vortex-shedding, pressure reducing valves, or turbulent flow. Of these sources, reciprocating compressors and flow-induced vortex-shedding produce the majority of pulsations that cause noise and vibration problems in pipelines. This paper will focus primarily on pulsations created in a gas piping system by positive displacement compressors. Pulsation is a periodic fluctuation in local pressure imposed on the fluid in a piping system by a machine or occurring locally as a result of a flow disturbance phenomenon. The Bernoulli principle describes that a variation in pressure will produce a corresponding variation in velocity (see Equation 1 for a simplified form). While the Bernoulli principle is rarely used in calculating pulsation amplitudes in piping systems, it is an important relation to understand when solving flow related problems. Figure 1 gives a visual example of the molecular redistribution of molecules imposed on a gas by a reciprocating compressor to create a pressure wave that travels through a piping system.

Abstract Software for the simulation of the transient behavior of natural gas pipelines commercially available, however, due to their high computational demands, they do not allow real time simulations. Further, they are difficult to set up if the goal is to match measurement data from SCADA systems or compressor stations for existing pipelines. To overcome this difficulty, a state space approach is used to capture the transient behavior of the pipeline. The general approach takes a published method from the literature that derives transfer functions and state space equations from one-dimensional Navier-Stokes and extends the method to reduce uncertainty in modeling parameters. The present method is validated against results in the literature. Then, a pipeline is modeled with commercially available, well established software, and the transient behavior is simulated and the results are compared with the present method. The main contribution of the paper is the extension of the stat-space formulation to remove uncertainty in pipe-roughness assumptions through systematic estimation of friction factors. Introduction Natural Gas Pipelines are an efficient method to transport energy over large distances. The transportation of natural gas and/or blends of natural gas and hydrogen over large geographic areas requires efficient operation of compressors and other related facilities. The scheduling of flows throughout a piping network is a great challenge to control theory. Many gas pipelines are operated under unsteady operating conditions, which in turn causes significant fluctuations in the operating conditions for the compressor stations in these pipelines. These fluctuations are the result of varying demand, as well as varying gas supply. For a given pipeline segment, the gas supply pressure and flow into the pipe are subject to change as are the pressure and flow demand on the delivery side of the pipe. These conditions, as well as their timing are only predictable to a degree.

ABSTRACT Many gas compressor stations use multiple gas turbine driven centrifugal compressors. In many instances, the units are not identical. The challenge is to control the units such, that certain operational parameters, for example fuel consumption, pipeline capacity or maintenance requirements, are optimized. The discussion includes the use and sizing of multiple units, the arrangement of units, the arrangement as push or pull compression, as well as examples of optimization strategies at various levels of sophistication, up to and including the integration of hydraulic and turbomachinery optimization. The benefits of methods that control compressors for the same turndown, or to control all gas turbines for the same load. This methodology can be derived and discussed for the case of identical machines, and will be expanded for the case where the compressors and their drivers are not identical. The control system has to rely on measurable parameters, but the system has to be reliable even if parameters that are not directly measured change during operation. The paper describes a variety of optimization methods, starting with a simple algorithm, then comparing equalization methods, and finally illustrating the capability of methods that combine turbomachinery optimization and the optimization of pipeline hydraulics. An example demonstrating the potential fuel savings of such an optimization is given.

Abstract Many things can cause rapid transients in gas pipelines, such as the sudden shutdown of compressors, or the abrupt changes in flow rate due to leaks. The hydraulic simulation of these rapid transients requires a mathematical model capable of modelling the detailed rarefaction wave. This also enables the accurate analysis of the impact of sequential valve closures along the pipeline. To minimize potential flow interruptions the highly accurate modelling of the pipeline dynamics can be used to understand and tune the behavior of the automatic shutdown valve (SDV's). By simulating the pipeline behavior, offline analysis can be performed in a safe environment without interrupting pipeline operations. Automatic shutdown valves are designed to automatically close mainline valves in the case of a major pipeline leak or rupture to minimize pipeline leakage. Calibrated to detect a sudden pressure differential drop between a reference reservoir and the pipeline, automatic shutdown valves can respond to more than just pipeline leaks. Improper actuation of the line break mechanisms during pipeline operations can result in unwanted interruption of the pipeline flow if the calibration is not optimized. This paper discusses the pipeline behavior during the transient, the dynamic effects on the automatic shutdown valves, and covers an analysis of first and second order mathematical solvers. The results of the simulations are validated throughout with a comparison with field test measurements. Introduction A piping system is the most common method for transporting fluids between two locations. There are many challenges in the safe transportation of fluids in pipeline systems, particularly during rapid transients. The use of mathematical models to simulate these rapid transients makes pipeline operations safer. Mathematical models enable detailed analysis of transients following sudden compressor shutdowns, and abrupt flow rate changes caused by leakages. This detailed analysis provides an understanding of the behavior of the rarefaction wave as it propagates from the source of the change.

ABSTRACT This paper deals with the problem of transient optimization of gas transmission networks of arbitrary structure. We assume that the transient state of the network is described by the system of partial differential equations of hyperbolic type expressing mass, momentum and energy conservation in pipes and flow conservation in nodes. The optimization criterion is to minimize the fuel consumption of the compressor stations. Each compressor station can be equipped with gas turbine driven centrifugal compressors and/or motor-compressors, and has a local optimization algorithm for given suction pressure, discharge pressure and flow rate. The results of the solution of the transient flow model in each branch of the network are used to identify compressor station suction pressures and flow rates at each time step. Next the nonlinear programming problem is solved to evaluate the type and the number of simultaneously operating compressors so that the total fuel consumption in each time interval is minimized subject to the constraints imposed. If the difference between consecutive values of the input variables (in subsequent time steps) is less than the accepted value, the optimization algorithm is not altered. Where the difference between the suction and discharge pressure values is less than the minimum, the algorithm switches off the compressor station. The method presented has been verified experimentally on the telemetry data of a large-scale gas network. The practical verification has confirmed the correctness of the algorithm. INTRODUCTION AND BACKGROUND Proper functioning of the gas market requires safeguarding security of gas supplies in a competitive market framework. Therefore the operation of the gas network is managed with a view to ensure a secure supply to all customers while at the same time minimizing the operational costs and environmental impact of pipeline operation.

ABSTRACT Centrifugal compressor systems include many different subsystems that facilitate performance monitoring, operational controls, vibration monitoring, and surge protection, etc., that are integral to the safe and proper operation of the compressor station. Centrifugal compressor stations can be operated in different configurations and for different services that include units in series, parallel, or mixed with reciprocating units. Due to changing market demand or changing operating conditions, there are higher required compression ratios on the steady operating state of compressor units in order to achieve higher flow demands. This forces the compressor to operate in a higher energy state and taxes the anti-surge control system during normal operational variances and during the sudden transient emergency shutdown (ESD) events. The anti-surge system maintains forward flow through the compressor by reducing the compressor pressure ratio and increases suction flow by diverting the compressor discharge flow path to the compressor suction piping through a recirculation loop. When designing the piping system, designers may be conservative in adding a hot gas bypass valve to assist the anti-surge valve (ASV) in protecting the compressor unit from surge during a high-energy fast stop. The advantage of the additional valve is the increased capacity of the recycle system, while the disadvantages are increased system complexity, additional capital cost, possible unit overheating, and space considerations. Refined system design and detailed engineering analysis considering various aspects, including but not limited to actual piping volumes, piping distances, ASV selection, hydraulic resistances, control systems, and compressor inertial coast down data that will increase the accuracy of hydraulic flow modeling and assist in determining if a hot gas bypass valve is required. This paper presents a general approach for conducting centrifugal compressor dynamic modeling and the considerations that should be taken when designing a recycle loop with or without a hot gas bypass. In addition, cases studies are presented to illustrate how to possibly avoid hot gas bypasses while increasing the effectiveness of the anti-surge system.

ABSTRACT The SCADA systems are now the basis for monitoring the flow and quality of a given medium. The article describes situations that may occur in the transmission system in case the medium is a gas that is not homogeneous for all sources. For this reason, the SCADA system faces big challenges, both to ensure correct data and operation consistency (7 days / 24 hours). The SCADA systems are the basis for additional systems: simulation systems - predicting what will happen in the transmission system, forecasting systems - consumption forecasting e.g. succeeding 24 hours and balancing systems - customer settlements. This article describes the problems that may occur in SCADA systems specifically in simulation systems, in the absence of or invalid input data. The basis for the correct functioning of the simulation calculations cooperating with SCADA systems is correct input data. The input data for such calculations can be downloaded directly from devices located on industrial objects as well as can be created/generated - various types of conversions performed by IT systems. This article describes situations in which invalid data causes disturbance of calculations. For example, in case of calorific value calculation, even a momentary invalid data concerning the gas composition may cause incorrect calculation results. The return to the correct calculation values of different cases may occur after a longer period. The article describes how to deal with such situations. We also present what may happen in the case of receiving incorrect data for nonlinear elements as well as for input or output points. There are also examples presented how these situations may be dealt with, and what possible settings should be included in SCADA systems to eliminate such cases or limit their impact.

ABSTRACT Operators of long natural gas pipeline networks with multiple gas compressor stations are looking for ways to optimize operations, reduce fuel consumption and costs, and maximize producer and consumer throughput in real time. This paper introduces a unique method to optimize these complex natural gas pipeline total value streams and achieves the stated objectives by integrating turbomachinery algorithms into a high-fidelity simulator to improve total model and simulation accuracy. Through much trial and error, the authors discovered how to account for the physical network size and how the combination of turbomachinery and gas pipeline algorithms as well as advances to auto-tuning methods may be used to solve the challenge of simulating complex natural gas pipeline networks in real time. Auto-tuning algorithms and the simulator results were validated with real field data from natural gas pipelines to ensure model and simulation accuracy. Technological advances incorporated into the pipeline simulator included a new parsing engine, advanced regulatory control, and incorporating turbomachinery algorithms for mixed mode operations (gas compressors driven by gas and electrical turbines as well as reciprocating engines). This paper describes our method and these advances and demonstrates how they may be applied to all natural gas pipelines to significantly improve operations, reduce costs, and improve the operating envelope. INTRODUCTION Natural gas transmission pipelines transport large quantities of gas across long distances and deliver it to major consumers (local distributors, large industrial end users, electrical generation facilities). Natural gas is introduced into a pipeline transmission system at various points, such as LNG terminals, processing facilities near supply fields, and interconnections with other gas pipelines. This gas is transported in high-pressure pipelines and a series of compressor stations. Compressor stations provide the power required to transport the gas in the pipeline from one location to another and usually contain more than one compression unit. A unit is defined as a combination of a compressor and its engine. A gas compressor station may have a diverse combination of units, resulting in a more complex operational envelope not possible to solve using traditional optimization techniques. The methodology presented in this paper is unique in that it was designed to model diverse unit configurations and to generate optimization results based on multiple objective functions.

ABSTRACT One of the key goals of pipeline hydraulic optimization is the capability to minimize fuel consumption of gas turbine driven centrifugal compressors. This requires an accurate, and computationally efficient method to calculate the fuel consumption of a gas turbine driven centrifugal compressor system. This feature is available for any current pipeline modeling software. The issue, however, is in accuracy of the currently provided methods of calculations. Authors have found that errors in the leading software exceed 2-3%. More accurate computations would allow pipeline operator to increase system's throughput and also more accurately assess the station and pipeline fuel cost. A common requirement is to calculate the fuel flow of the gas turbine for a given compressor operating point. In this case, the compressor speed and power consumption (and therefore, the shaft power at the power turbine and the power turbine speed) are known. To accurately calculate the station fuel consumption the user requires the gas turbine performance data for each particular compressor station, considering the station's site conditions which include ambient temperature, humidity, and the site elevation. This information is often unavailable for the pipeline analyst, so one of the main objectives of this paper was to find universal set of data that would be able to provide most accurate fuel consumption for all compressor stations regardless their different site conditions. This paper presents the results of a study conducted for a compressor stations where two different methods were used to reduce the accuracy of compressor station fuel calculation down to around 0.25%. The first method relates to elevation correction and it uses engine data files that contain the fuel consumptions data for the sea level only. The basis for this method is that gas turbine efficiency doesn't change with the change of the site elevation assuming the same percentage of turbine's part load. The second method is a "Power Turbine Off-Optimum Speed" iteration process where the actual fuel consumption value is found using some iterations between power turbine optimum power and speed until the target value is found. As in the "Elevation Correction" method the only one set of turbine's sea level data is needed and can be used for any site elevation. The methods described avoid shortfalls of previous methods when dealing with Lean-Premix Low Emissions gas turbines, and are simple enough to provide a effective means to properly account for part load and off-optimum gas turbine performance at arbitrary operating conditions. Both methods can also be used to calculate the fuel consumption at any given ambient temperature by interpolating between two closest sets of ambient temperatures.

ABSTRACT The paper concerns the problem of optimal control of a natural gas transmission system consisting of a compressor station and adjacent pipeline sections. Natural gas is supplied with two types of compressors, namely gas turbine driven centrifugal compressors and motor-compressors. For a given simulation scenario, the suction pressure, suction temperature, discharge pressure, and total compressor station mass flow are predicted from the non-isothermal transient gas flow model. Next the nonlinear programming problem with continuous and, in case of motor-compressors, discrete variables is solved to evaluate the type and the number of simultaneously operating compressors, while determining such a distribution of the capacity that the total unit fuel consumption in each time interval is minimized subject to the constraints imposed. The paper presents an algorithm of automatic search for the optimal values of the operating parameters of the compressor station. The method presented has been verified experimentally on the telemetry data. INTRODUCTION AND BACKGROUND Natural gas is usually transported by pipeline networks which serve as the most cost effective transportation means. Transmission systems usually have a linear topology corresponding to a linear arrangement of compressor stations. The fuel consumption of compressors is responsible for a large fraction of the costs of gas network operation. Luongo et al. (1989) reported that AGA estimates the operating cost of running the compressor stations to vary between 25% and 50% of the total company's operating budget, therefore minimizing fuel usage is a major objective in the control of gas transmission costs. This work is concerned with the optimization of a single compressor station operated under transient conditions. More specifically, we consider variable boundary conditions, i.e. unsteady inlet and outlet pressures together with a variable flowrate through the compressor, and search for the optimal values of the operating parameters that minimize the running costs of the compressor station.

ABSTRACT Performance test provides important information about whether a newly constructed pipeline can achieve the design capacity and transportation efficiency. The field performance test also provides mechanical performance correction factors for compressors as part of the commissioning procedure of natural gas transmission pipelines. The EPC contractors are usually asked to ensure that the pipeline can achieve the delivery pressures and flow rates under the protocols agreed upon. Pipelines are normally designed to achieve certain flow rates in different phases. However, it is not uncommon to see pipelines falling short on gas supply or user demand during the time period that the performance test is scheduled for. The available pipeline inlet pressure and flow rate are lower than the guarantee conditions described in the performance test protocols. The quality of the gas supply may also create unexpected problems on the interpretation and evaluation of the performance test results. Therefore, it is necessary to conduct the performance test at lower pressures and lower flow rate conditions. This paper presents the methodology, strategy, procedure as well as a real life example of a simulation based performance test of a gas pipeline. The method presented offers a practical tool to validate pipeline performance by evaluating the fundamental physical parameters. This method can also be used in assessing the pipeline hydraulics conditions for potential corrosion issues (ID change), roughness changes, BSW deposition or other issues influencing pressure drops in the pipeline. INTRODUCTION AND BACKGROUND Performance test is an important part of the commissioning procedure of natural gas transmission pipelines after their construction. The EPC contractors are responsible of ensuring the pipeline can achieve the delivery pressures and flow rates under the protocols agreed upon. Pipelines are normally designed to achieve certain flow rates in different phases. However, it is not uncommon to see pipelines falling short on gas supply during the time in which the performance test is scheduled. During the economic down turns, the pipeline users may also have difficulty accepting the gas at the flow rate required to achieve the pipeline guarantees. In these circumstances, the available pipeline inlet pressure and pipeline flow rate are lower than the guarantee conditions described in the performance test protocols. The quality of the gas supply may also create unexpected problems in the interpretation and evaluation of the performance test such as the presence of black powder. Therefore, it is necessary to conduct the performance test at lower than anticipated pressures and flow rate conditions. The question is how to assess whether the pipeline performance will achieve the guarantees with the data collected at a lower pressure and lower flow conditions? The answer lays in the assessment of the pipeline parameters using measurement data at lower pressures and flow rates, along with gas pipeline hydraulic simulations at guarantee conditions. This paper presents the methodology, strategy, procedure as well as a real life example of a simulation based performance test of a gas pipeline.

ABSTRACT As dependence of the bulk electric power system on gas-fired generation grows, more economically efficient coordination between the wholesale natural gas and electricity markets is increasingly important. New tools are needed to achieve more efficient and reliable operation of both markets by providing participants more accurate price signals on which to base their investment and operating decisions. Today's Electricity energy prices are consistent with the physical flow of electric energy in the power grid because of the economic optimization of power system operation in organized electricity markets administered by Regional Transmission Organizations (RTOs). A similar optimization approach that accounts for physical and engineering factors of pipeline hydraulics and compressor station operations would lead to location- and time-dependent intra-day prices of natural gas consistent with pipeline engineering factors, operations, and the physics of gas flow. More economically efficient gas-electric coordination is envisioned as the timely exchange of both physical and pricing data between participants in each market, with price formation in both markets being fully consistent with the physics of energy flow. Physical data would be intra-day (e.g., hourly) gas schedules (burn and delivery) and pricing data would be bids and offers reflecting willingness to pay and to accept. Here, we describe the economic concepts related to this exchange, and discuss the regulatory and institutional issues that must be addressed. We then formulate an intra-day pipeline market clearing problem whose solution provides a flow schedule and hourly pricing, while ensuring that pipeline hydraulic limitations, compressor station constraints, operational factors, and pre-existing shipping contracts are satisfied. Furthermore, in order to support the practical application of these concepts, we provide a computational example of gas pipeline market clearing on a small interpretable model, and validate the results using a commercial pipeline simulator. Finally, we validate the modeling by cross-verifying simulations with SCADA data measured on a real pipeline system.

Abstract In this paper, we present an integrated simulation tool for analyzing the interdependency of natural gas and electric power systems in terms of security of energy supply. In the first part, we develop mathematical models for the individual systems. In part two, we identify the interconnections between both systems and propose a method for coupling the combined simulation model. Next, we develop the algorithm for solving the combined system and integrate this algorithm into a simulation software. Finally, we demonstrate the value of the software in a case study on a real world interconnected gas and electric power system of an European region. Introduction The ongoing integration of renewable energy resources into the energy portfolio of the European Union is connected with an increased interconnection between the different critical energy infrastructures (CEI). The interdependency between natural gas and electric power systems, for instance, is expected to grow in the near future. On the electric side, the demand for flexible backup power for intermittent renewable energy sources is increasing, which can be met by gas fired power plants (GPP) connected to the gas and electric grid, while on the gas side an increased use of electric power to operate facilities in the gas system can be observed (e.g. electric driven compressors, electric power supply to LNG Terminals etc.). Moreover, the present advancement in the Power-to-Gas technology will significantly contribute to the coupling of both systems. These trends suggest the need for simulation models to examine the depth and scope of these interdependencies, how they may affect the operation of both systems and how to proactively approach the bottlenecks that may emerge. Furthermore, developing combined gas and electricity models will also facilitate the development of Risk Assessment for this type of coupled networks. In this paper, we present an integrated simulation tool for analyzing the interdependency of gas and electric power systems in terms of security of energy supply, i.e. the uninterrupted supply of energy to its customers (e.g. commercial, residential, industrial customers, public services and power generation companies) particularly in case of difficult climatic conditions and in the event of disruptions [1]. The first part of the paper, focuses on developing the mathematical models for both systems. The second part, elaborates the interconnections between both systems and derives coupling equations for the combined system, followed by a description of the algorithm for solving the resulting system of equations. Finally, the capability of the simulation tool is demonstrated by applying it to a real world instance.

Overview Compressor stations play an important role in the successful design of gas pipelines; the right choice of centrifugal compressors and drivers is a key factor in the success of the entire project. The currently available design criteria for this type of equipment ensure generally high thermodynamic performance and, consequently, minimize the requirements for nameplate capacity and energy consumption, permitting substantial savings in operational costs over the project's entire economic life. When using mechanical equipment in a gas pipeline compressor station, one of the main issues that needs to be solved is the number of units required to meet the pipeline's throughput capacity criteria. Various solutions can be used, depending on the pipeline's load profile. Another factor worth considering is the fact that gas turbines can generate significantly more power at lower ambient temperatures. This means that the driver's relative capacity can vary even under continuous pipeline load. This study evaluates a typical trans-continental pipeline with a number of compressor stations. The simulation includes the determination of the pipeline's exact hydraulic indicators. The local environmental conditions are taken into account where there are cases of significant ambient temperature fluctuations. To calculate gas pipeline availability factors, the Monte Carlo system will be used. As defined by Evans and Olson (1998), Monte Carlo simulation involves using statistical probability to evaluate the resulting distribution of a variable which, in turn, depends on several other independent variables. The Monte Carlo simulation is often used to evaluate the degree of risk posed by an event that is new but expected. The focus for this publication is the gas pipeline availability factor that can be achieved using various configurations based on actual reliability and availability indices. Various statistical methods for calculating reliability and availability will also be considered. Another issue which will be examined that has a considerable impact on operational costs is fuel gas consumption. In this case, the number of installed units has a great impact on the annual volume of fuel consumption, as well as on the pipeline throughput based on different operational scenarios. Introduction The rising world demand for gas has created the need for new gas pipelines that can deliver gas to markets located a long distance from the supply source. For long-distance pipelines, gas transportation costs include increasing customer delivery costs, which can amount to 30-50% of the total costs for the receiving terminal. These transportation costs can be controlled by optimizing fuel consumption, equipment acquisition costs, equipment maintenance costs, and the equipment's reliability and availability. Pipeline pressure, flow, and other parameters influence the configuration of the compressors at any given station. The number of units, the distance between stations, the requirements for standby equipment, and the usage of series or parallel configurations at a certain station are all issues that arise along with the type of drives and compressors. Previous publications (Santos, 2004; Ohanian et al., 2002; Kurz et al., 2003) evaluated the relative advantages of series and parallel configurations, as well as the number of units per station. When designing a compressor station or a new pipeline, a definitive analysis of the number of stations needs to be performed. This includes: the steady-state and transient capacity conditions and system requirements, the requirements and ability to improve capacity and output, the system units' availability, the total cost of ownership, and the total cost of delivery to shippers and customers.

Abstract While planning transmission pipeline expansions, engineers must decide which pipe diameters to use as well as where to locate compressor stations. Engineers must make these design decisions based on the desired capacity of the pipeline, the cost of the pipe used, and the cost of compression. A significant amount of time may be spent running case studies to determine the optimum compressor station location and pipe sizes. This paper presents an automated technique for locating compressor stations throughout the pipeline based on pipeline and compressor constraints. The compressor location data along with pipeline and compressor costs are generated for a series of pipe diameters and pressure scenarios. The resultant design cases are then analyzed to uncover data trends and design alternatives which allow the engineer to make informed pipeline design decisions. Introduction Designing a gas transmission pipeline requires a significant amount of engineering and economic analysis. Not only must a suitable pipeline route be selected, but, based on the design capacity, engineers must decide on pipe diameters, internal pipe coatings, pipeline maximum allowable operating pressures (MAOP), and optimum locations and sizes of compressor stations. Pipeline installation and operating costs depend heavily on these decisions, as each of these comes with an associated cost. The price of pipe installation increases significantly with pipe diameter. If larger MAOPs are desired, pipes must have thicker walls with sufficient hoop strengths to meet the greater pressure demands leading to larger capital expenses. Compression comes with significant operating costs including fuel, maintenance and management costs. There is a tradeoff between these selected parameters. For a given capacity, if larger pipe diameters or higher MAOPs are chosen, compressors may be located further apart reducing compression costs, but pipe installation costs increase. Conversely, if compressors are placed closer together, pipe capital costs may be reduced by using smaller diameter or thinner walled pipes at the expense of higher compression costs. Large amounts of money can be saved by selecting the optimum set of pipeline parameters. Johnson and Wallooppillai (2006) give an excellent description of the process of designing a pipeline, along with the associated costs, while Arsegianto et al. (2003) and Elchiekh et al. (2013) give descriptions of the costs associated with pipeline construction and operation.

Abstract One of the necessities of a simulation software is to model the behavior of compressor stations. The main device modeled in a compressor station is a compressor. The article presented concerns mathematical description of centrifugal and axial compressors, the most frequently used equipment in the gas transportation pipelines or pipeline networks. Traditionally, both in the machinery industry and in the gas industry, these are mainly modelled using complete biquadratic polynomial approximation of the working space. The characteristics parameterized by the rotation speed values are then represented as 2nd-order parabolas in the satisfactorily invariant (relative to inlet gas status) coordinate system Q vol - H ad . Exactly the same approach is basically used for the working space in efficiency variables ? - Q vol . and, parameterized by the efficiency values, also projected (and displayed) in the same invariant coordinate system Q vol - H ad . However, there have been new developments in design and production area, and also the community of the user wishes - namely we are talking about axial compressors that contain several compression stages integrated internally. The characteristics of such devices can no longer be described precisely enough in the traditional simple way represented by 2nd-order parabolas, so better methods of modelling needed to be found. After some testing of various methods, we propose to model these compressors using linear interpolation approach, when the boundaries of a revolution working area are described using cubic splines and the working point parameters are found using linear interpolation within a small enough quadrangle defined by these splines. There are some challenges using this approach, namely a need to harmonize mathematically precise solution and possibilities of computers. Finally, we realized that the new approach is a bit slower to traditional one, but on the other hand, when comparing the precision, the result is significantly better in favor of the new model. In conclusion, with the advancements of technology, new ways of modelling need to be constantly devised. Our new way of modelling compressors is fast and robust enough to be rolled out to our customers in order to improve the model quality specifically for the compressors that cannot be processed in a traditional way.

Abstract Centrifugal compressors, especially variable speed machines, offer the user considerable advantages resulting from the availability of a wide range of operating flow and head. The performance map with multiple speed lines, for example, can increase from two (2) to three (3) dimensions by simply adding changes to suction conditions. The convenience afforded by the wide range of operating points, however, presents a challenge in modeling the performance. The traditional methods of modeling - table lookups and fan laws fail to sufficiently reduce and eliminate inaccuracies due to their tedious nature, the shape of the performance curve and interpolation method. They work, but not well enough. This paper proposes a new method of modeling compressor performance using non-dimensional performance parameters apart from lookup tables and fan laws. The case is made for utilizing work input coefficient, polytropic head coefficient and total flow coefficient as non-dimensional parameters that can not only model the compressor with all the variability mentioned above, but also indicate when there is a performance problem. This new approach proposes the use of real time input data and response capabilities. Through the methods put forward in this paper, a user will have a realistic performance model, and a performance monitoring and alert system that can be used as a real-time feedback mechanism into the gathering system model. Introduction In today's highly competitive low margin natural gas market gaining an edge by keeping production costs low is an imperative. Identifying and realizing any and all efficiencies in natural gas production and transmission could significantly improve the profit margin over long term operation. The centrifugal compressor, as a critical component in this process, provides the flexibility in capacity range and head as required by the process. Despite these benefits, it has been a challenge to monitor the aerodynamic health of the machine considering the number of variables affecting the operating condition of the compressor; especially the inlet conditions, compressor speed, head, and inlet mass flow. A common evaluation, for example, utilizes the compressor's OEM (Original Equipment Manufacturer) performance curves. While the OEM provides a variety of performance curves based on different sets of operating conditions, it leaves a lot of room for interpretation and, consequently, error. With all the variability mentioned above, finding the machine's current operating point on a predefined set of curves can be difficult. This generally leaves the engineer to make an educated guess regarding machine performance against the original design.

Abstract New growth in shale gas production has changed the nation's energy point of view in recent years while creating new challenges in processing and transportation due to differences in specific gravities, Wobbe Index, and higher heating values. New fluid properties are affecting the design and operation of pipeline systems and compressor stations; therefore, a good quantification of their effect on the operating conditions of typical pipeline systems and compression equipment is needed. Many compressor stations are reversing flow direction and operating with a different gas composition than what the station was originally designed to process. Using a pipeline simulation method, this paper will review the effects on the efficiency and performance of compressors when exposed to varying natural gas compositions as well as the effect on the pipeline losses. This paper will also include the case study results of a pipeline system and its associated compressor stations. Background and Introduction In recent years there have been significant increases in natural gas production from shale deposits throughout the United States. In an effort to reduce the cost of compressing, processing and transporting this shale gas, many compressor stations in proximity to these deposits are reversing flow direction and operating under new conditions. Principally, these compressors are operating with a different gas composition than that which the stations were originally designed to process. With the expansion of extraction from shale formations, primarily throughout the United States, natural gas found at the numerous locations vary in composition. There are currently shale gas reservoirs spanning the north and south regions of the United States including New York, Pennsylvania, Wyoming, Colorado, Illinois, Texas, Oklahoma, and New Mexico. Individual components, such as nitrogen, methane and hydrocarbons, within these gas compositions can differ by over 10% mol subject to location. Furthermore, the component quantities in different wells at the same location can vary by similar magnitudes. The nitrogen content of the Barnett Shale formation in north-central Texas, for example, has been recorded to vary as much as 7% mol from well to well. Carbon dioxide and other heavy hydrocarbons have been measured at different wells at the same shale formation and been found to differ by over 10% mol. The composition variety of multiple United States shale gas locations is presented in Figure 1 and Table 1.