Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Upstream
ABSTRACT: In recent years there have been a number of papers that have addressed various topics within the general subject area of thermal modeling in a pipeline. These have all been worthy papers and certainly present the PSIG membership with a reasonably comprehensive view of the subject. However, the approach to solving the temperature equation together with the hydraulic equations has only been briefly discussed and relatively few comparisons made between the alternative strategies. This paper investigates the differences between a fully coupled system, in which all three equations used to describe the flow of fluid in a pipe are solved simultaneously, and a decoupled system, in which the thermal equation is solved separately from the hydraulic equations. The advantages of such a decoupling are reduced complexity and improved computational speed. But what is the cost? Is the accuracy of a decoupled system compromised? However, can a properly constructed decoupled system produce solutions that are indistinguishable from those produced by a fully coupled system? To compare the different approaches a comprehensive set of test cases has been developed. As well as highlighting specific thermal modeling phenomena, the results of these tests demonstrate where differences in the solutions lie and the magnitude of such differences: ultimately the tests are used to determine the credence of decoupling the thermal solution from the hydraulic solution. INTRODUCTION Over the past 30 years there have been many papers presented at PSIG on the subject of thermal modeling ranging from tutorials on the physics and thermodynamics[1],[2], to comparison of different solution methods[3],[4], verification[5] and accuracy[6] and why thermal modeling is important in the real world[7],[8]. A number of these papers[3],[4],[8] also present investigations into various simplifications that can be made to the physics of the thermal model and to what extent these simplifications affect the accuracy.
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (0.96)
- Reservoir Description and Dynamics > Reservoir Simulation (0.93)
- Reservoir Description and Dynamics > Formation Evaluation & Management (0.93)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers (0.68)
ABSTRACT: The authors will discuss the challenges involved in the design and predictive modeling of a proposed 1,200 mile (1,900 kilometer) liquid ethane pipeline. Comparisons between ethane and other common liquid product streams will be presented. The implications of these differences will be shown on how they relate to design consideration. Commercial considerations as well as project timing will also be discussed. WHAT IS ETHANE At the standard conditions of 60ยฐF and 14.7 psia, ethane is an odorless colorless hydrocarbon gas. Ethane is an alkane that is a common component of natural gas. Ethane has a relatively high heating value of 1630 BTU. During the processing of natural gas, ethane and heavier hydrocarbons are removed from the rich natural gas stream in order to meet the pipeline quality specifications of a net heating value of 1100 BTU. Ethane is one of the lighter hydrocarbon components of natural gas as depicted in Table 2. One can see that the progression of heavier hydrocarbons from methane adds one carbon atom and 2 hydrogen atoms and a corresponding ~14.03 g/mol molecular weight increase. The removal of heavier hydrocarbons from the rich natural gas stream creates a lean natural gas stream and mixture of hydrocarbons liquids (natural gas liquids). Often this mixture of ethane, propane, butane and heavier hydrocarbons is referred to as a demethanized natural gas liquids (NGL) mixture. A majority of the ethane is transported in this NGL mixture to centralized locations. A small remainder of the ethane stays in the leaner natural gas stream. At these centralized locations, component product streams are created through fractionation of the demethanized NGL mixture, and sold as a commodity. The commoditized components are then delivered to the end user for use. In the United States ethane futures are sold on the NYMEX electronic futures exchange.
- North America > United States > West Virginia (0.47)
- North America > United States > Pennsylvania (0.47)
- North America > United States > Texas (0.46)
- (2 more...)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Midstream (1.00)
- Energy > Oil & Gas > Downstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.71)
ABSTRACT: This paper discusses the optimization of linepack usage in gas networks to meet the demand for flexibility in consumptions. The rapid development of flexible gas plants known as CCGTs (Combined Cycle Gas Turbines) and the recent evolutions of the energy markets makes it a key issue in computing capacities for TSOs. This paper describes the operating principles of tools designed by CRIGEN to address this subject, highlighting the respective roles of steady-state- and transient-modeling in that task. INTRODUCTION GRTgaz owns, develops, maintains and operates the main part of the French gas transmission system (a highly meshed network composed of over 20 000 miles of pipes, 25 compression stations, over 4500 delivery points, that transmitted 640 TWh of gas in 2011). In the last few years, GRTgaz, has experienced challenging evolutions in energy regulation and in its relation to energy markets. One of them, maybe the most remarkable, is the development of many CCGTs. The capacities of those consumers are expected to double between 2010 to 2020, to account for a quarter of the transmitted flows in 2020. This paper presents how CRIGEN combined its existing tools and its expertise in the fields of complex networks, steady-state and transient modeling to help GRTgaz compute and optimize the available linepack for a given set of transmission capacities. Since the notion of available linepack is relative to different factors, rather than focusing only on the computation of a simple number, the paper also discusses the different impacts of the most remarkable factors we studied. We will then discuss the use of linepack in operations, and how the dynamic of utilization of linepack affects the value of the available linepack : depending on how linepack is used, there can be different amounts of available linepack.
- Energy > Power Industry > Utilities (0.54)
- Energy > Oil & Gas > Upstream (0.54)
Hydraulic Modeling of an Off-Shore Crude Oil Emulsion Pumping System
Garcia-Hernandez, Augusto (Southwest Research Institute) | Viana, Flavia (Southwest Research Institute) | Delgado-Garibay, Hector (Southwest Research Institute) | Rayon, Eduardo Elias (PEMEX Exploracion y Produccion) | Dorantes, Moises Leon (PEMEX Exploracion y Produccion) | Prior, Marco Antonio Munoz (PEMEX Exploracion y Produccion)
ABSTRACT: One of the most important facilities of the PEMEX Exploration and Production off-shore transport system has been hydraulically analyzed to determine its current transport capabilities and assess the effect of a possible change of the transported crude oil properties. This facility transports crude oil emulsions from diverse production platforms to an on-land facility that is located 25 miles away from the platform. The current system operates with crude oils in the range of 19ยฐ API; however, an increase in the production of heavy oil has been forecasted for the next few years. Thus, the existing pumping equipment and pipeline system need to be evaluated to confirm their satisfactory operation with the expected new mixtures of approximately 16ยฐ API. The existing system is a complex, interconnected platform network where different crude oils are mixed and pumped into various pipelines. A water-in-oil emulsion is presented in the system and its composition changes with the different streams that are being mixed in the system. In addition, water cuts and API values vary based on the field that is being produced. A dramatic change of the crude oil quality and API is expected in the next few years. Therefore, the existing booster system will require upgrades and modifications to handle the new operating conditions while the crude oil production is increasing. Currently, the pumping system transports a 350 cP crude oil from an off-shore platform to an on-land receiving terminal through two 36-inch pressurized pipelines. The system includes ten centrifugal pumps; however, an upgrade of the facility will demand the operation of only six pumps (1-6) for the light crude oil. Therefore, it was required to determine if the existing centrifugal pumping equipment, driver, and pipeline system will have the capacity to handle the new conditions while fulfilling the flow rate requirements.
- North America > United States (0.68)
- North America > Mexico (0.67)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers (1.00)
ABSTRACT: This study compares two natural gas compressor facility vent header designsโone designed with steady-state calculations and one designed with a transient analysis. The steady-state design will also be analyzed with the transient software to determine how the design might perform in an emergency. The example facility used for this study is based on an operating compressor facility in the Barnett Shale area near Ft. Worth, TX. It includes 8 automated block valves, 16 pressure relief valves, and the piping that connects it to the blow down silencer. The predicted venting performance for each design is also compared to the actual venting performance at the example facility. INTRODUCTION During start-up, shut-down, and in emergency situations natural gas facilities are designed to release the gas in the station piping to a vent gas header system. In an emergency such as a fire or over pressure condition, quickly releasing the pressure on the station piping reduces the risk of a serious explosion. The vent gas system may take the gas to a flare or to a blow-down silencerโdepending on the quality of the gas and the sensitivity of the surrounding area. Inlets to the vent gas header include automated block valves, which are opened manually or by set points in the station's programming. There are also pressure relief valves on the vent header, which open if the pressure in the piping exceeds the set point. Vent gas headers are designed to move a large amount of gas in a short amount of time at very low pressures. Correctly sizing the vent header piping is critical to avoid excessive back pressure, which can delay the evacuation of the gas from the station piping. This paper examines the differences in designing vent headers using steady state calculations versus transient analysis
ABSTRACT: This paper explains the impact of the interaction between system characteristics and compressor characteristics, both under steady state and transient conditions, and the concepts to optimize and control the units. Process requirements for compression systems require the adjustment of pressures and flows through these compressors. Control concepts need to consider both the characteristics of the individual compressor, as well as the characteristic of the compression system. Multiple unit installations, or installations with multiple compressors per train require specific process control considerations to match the compressors with the process system behavior and the objectives of the station or system operator. INTRODUCTION There are two objectives for compressor control: meeting the external process requirements and keeping the compressor within its operational boundaries. Typical control scenarios that have to be considered are process control, starting and stopping of units, and fast or emergency shutdowns. The interaction between a compressor and a compression system, in conjunction with control mechanisms and the compressor characteristic determine the operating point of the compressor in a given situation. For the single compressor the application of these control functions is fairly simple. For compressor applications with multiple compressors in series or parallel, multiple compressors driven by a single driver, multiple compressor trains operating together, or multiple suction or discharge headers the combinations of these control strategies can become very complex. External process objectives can be minimum suction pressure, maximum discharge pressure, or delivered flow. Compressor operational boundaries include surge, minimum speed, maximum speed, and in some instances minimum pressure rise (choke). The operating envelope of a centrifugal compressor is limited by the maximum allowable speed (or, for other control means, the maximum guide vane angle), the minimum flow (surge flow), and the maximum flow (choke or stonewall), and the minimum speed (Figure 1).
ABSTRACT: When a long gas pipeline is severed, gas escapes through a rarefaction wave that leads away from the break at sonic velocity. Immediately after rupture, the classical inviscid solution of rarefaction holds in which change proceeds evenly across the wave and the discharge is choked. After traveling a relatively short distance (a few hundred diameters) however, friction takes hold and reshapes the inviscid profiles so that the principal changes occur near the outlet. The practical consequences of friction are continual reduction of discharge rate and smoothing of the wavefront. Until the rarefaction reaches a distant boundary, depressurization is closely approximated by the similarity solution of a diffusion equation for density supplemented by evanescent boundary layers at the outlet and leading edge. The similarity solution yields a simple formula for the declining discharge rate with time and reveals that Excess Flow Valves, designed to isolate the line automatically, will not close if placed too far apart. INTRODUCTION Accidents in which a pipeline is severed are consequential. Large quantities of toxic or flammable material are rapidly discharged to atmosphere, and prompt action must be taken to protect the neighboring population. Understanding discharge dynamics in these cases is essential to assess potential hazards and develop appropriate risk mitigation plans. Dynamics at the leading edge of the depressurization wave that sweeps through the gas within the pipe also matters. Leak detection systems that rely on prompt identification of the rarefaction wavefront at critical locations may siginificantly lower risk posed by pipeline rupture. Local leak detection is often tied to Excess Flow Valves that shut automatically when the flow exceeds a threshold value. These nonlinear equations extend classical inviscid gas dynamics with algebraic friction and heat transfer terms that account for interaction of the gas with pipe walls.
ABSTRACT: In this paper we discuss the basic ideas behind a hydraulically accurate pipeline throughput maximizer. Given a model of the pipeline of interest, a current batch lineup, as well as a batch schedule and a list of scheduled equipment and/or station outages a detailed report on how to run a pipeline in order to maximize and/or verify throughput is generated through a series of successive steady state pipeline/dynamic calculations. Each steady state calculation solves the detailed mass, and momentum balances along with a dynamic accounting method that handles the energy balance, and determines a valve and pump line up that will maximize the product throughput on the line. The pipeline is assumed to remain in this steady state flow configuration as the simulation steps forward in time until the next eventโsuch as a planned outage, or new incoming batch enters the pipelineโat which time a new solution is computed. To account for thermal transients that could occur during the event interstitials, a method for handling heat transfer in such a steady state is presented. The result of such calculations is a series of pump and valve line ups, along with associated pipeline flows, pressures, linefills, and various component physical properties during each new period carried forward for an arbitrary amount of time, typically one month or less. Given the partial steady state nature of the calculations, the time requirement to simulate an entire months' worth of data is on the order of minutes. INTRODUCTION Understanding the current conditions in an oil or gas pipeline is critical for its day-to-day operations; understanding its medium term capabilities also must be considered by pipeline managers to successfully plan operations for days, weeks, and months to come ensuring smooth day-to-day operations and ensuring deliveries arrive as promised.
ABSTRACT: A new set of measurements of pressure drops and liquid hold-up taken at TEASistemi Laboratory under conditions of stratified gas-liquid flow has been used to improve the closure relations adopted in MAST, a new transient one-dimensional multiphase flow simulator. These data are relative to water-nitrogen flow in a 3.15 in (80 mm) horizontal pipe operating at pressures in the range 72.5-362.6 psig (5-25 bar). The results obtained allowed a more reliable description of stratified gas-liquid flow in hydrocarbon transportation pipelines. A comparison with the performance of other flow simulators is also presented. INTRODUCTION The simulation of gas-liquid flow in pipelines can be based on the solution of 1-D mass, momentum and energy conservation equations, [1]. These equations depend on a set of closure relations, in general of empirical nature. The closures adopted in commercial codes are similar to those proposed in the open literature, on the basis of data taken at atmospheric pressure, in small diameter pipes. These correlations have then been modified on the basis of experimental data taken at conditions which more closely resemble field conditions. Field data are used for the final validation of these codes. Notwithstanding the amount of work performed for code testing and validation, quite often the simulation of real pipelines remains unsatisfactory, the reason probably being that from one hand the quality of available data is poor, from the other, these data are quite limited and do not cover the full range of flow parameters encountered in practical applications. In the present work, we use different data sets relative to stratified gas-liquid flow in horizontal pipes to test major commercial codes used for pipeline flow simulation. Among these data we include a new set of measurements of pressure drops and liquid hold-up taken at TEASistemi Laboratory.
- Europe (1.00)
- North America > United States (0.46)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers (1.00)
ABSTRACT: Many of the transient models used to simulate gas and liquid pipelines are based on the method of finite differences (FD). FD models represent continuous model properties like pressure, flow rate, and temperature on a discrete grid of points in space and time, thereby approximating the true continuous partial differential equations (PDEs) governing fluid flow as a finite set of algebraic equations. This approach can be efficient and accurate but is subject to numerical instability and a host of other numerical problems if the grids aren't chosen appropriately. This article explores the situations in which these problems arise, how to diagnose them, and and what can be done about them. Explicit, fully implicit, and partially implicit FD models are examined. Recommendations for model building and model use are developed based on the results of a variety of test scenarios. INTRODUCTION All computer pipeline models embody some or all of a set of differential equations representing conservation of mass, momentum, energy, and possibly species and some other quantities. While a solution of the underlying PDEs is guaranteed to represent what would actually happen in the pipeline, the conversion of them into algebraic equations brings in the additional possibility of numerical errors: even if the PDEs were right, the solution might still be wrong. For the purposes of this paper we will consider only the conservation of mass, momentum, and energy PDEs. These are the required equations to make a pipeline model that solves for the pressure, temperature, and flow rate everywhere in the pipe system as a function of location and time. Just these three PDEs provide several distinct opportunities for the introduction of serious numerical errors into the solution. The process of converting a set of PDEs on paper to a FD solution scheme is known as "discretization".