Basics Of High Pressure Measuring And Regulating Station Design
Author(s): E. D. Woomer
Abstract/Introduction:
There is more to the design of a measurement facility than the word measurement suggests. Generally, the measurement arena may include any or all of the following: ?? Metering ?? Primary devices ?? Secondary devices ?? Tertiary devices ?? Control ?? Pressure regulation ?? Flow control ?? Overpressure protection ?? Gas Quality ?? Chromatography ?? Spot or composite sampling ?? Analytical instrumentation ?? Other ?? Odorization ?? Filtration / Separation ?? Heating Pneumatic and electronic instrumentation is scattered throughout each of the categories listed above. The detailed design of a measurement facility can become quite involved and exceed the space allotted in this paper. However, the fundamentals will be addressed in regard to the considerations for designing natural gas transmission pipeline measurement facilities. For the purposes of this paper, only metering and regulating (M&R) will be addressed.
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Document ID:
49C91830
Compressibility Of Natural Gas
Author(s): Jeffrey L. Savidge
Abstract/Introduction:
The accurate measurement of natural gas and natural gas related fluids is difficult. It requires care, experience, and insight to achieve consistently accurate measurements that can meet stringent fiscal requirements. It is particularly difficult to measure complex fluid mixtures that are exposed to: (1) a range of operating conditions, (2) dynamic flow and fluid property behavior, and (3) changing equipment conditions. The compressibility factor is a ubiquitous concept in measurement. It arises in many industry measurement practices and standards. Unfortunately the mathematical methods and data associated with it obscure some of the basic ideas behind it. The purpose of this paper is to provide background into the development of compressibility factor methods, discuss their use in natural gas measurement, provide examples of the behavior of the compressibility factor, and illustrate the level of uncertainty that current compressibility and related property standards provide.
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Document ID:
686EA108
Fundamentals Of Gas Measurement
Author(s): Jerry Paul Smith
Abstract/Introduction:
A knowledge of the Fundamentals of Gas Measurement is essential for all technicians and engineers that are called upon to perform gas volume calculations. These same people should have at least a working knowledge of the fundamentals to perform their everyday jobs including equipment calibrations, specific gravity tests, collecting gas samples, etc. To understand the fundamentals, one must be familiar with the definitions of the terms that are used in day-to-day gas measurement operations. They also must know how to convert some values from one quantity as measured to another quantity that is called for in the various custody transfer agreements. Below are listed some of the most commonly used terms and their definitions along with some examples of various conversions that must be made from time to time by people working in the natural gas industry:
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Document ID:
985F6563
Coping With Changing Flow Requirements At Exsisting Metering Stations
Author(s): James m. Doyle
Abstract/Introduction:
In todays competitive gas market, utility companies must meet aggressive market strategies or suffer the consequences. All industries have cash registers, and gas distribution is no exception. Our measuring stations are our cash register. The problem is, these stations were designed 10, 20, 30 or even 50 years ago, and are now performing tasks they were not designed for. Therefore, changes must be made. Measurement personnel today must be trained and taught to cope with changing flow requirements. But, modifying a station to meet todays aggressive market can be very expensive. Equipment, such as regulators and the primary element (the meter tube, the orifice plate holder, and the orifice plate), must meet A.G.A. 3 requirements. The secondary element (the recording device) can raise expenditures significantly. Sometimes modifications cannot be made to deliver the specified volume of product needed, and replacement of a complete station is even more expensive. Companies today must watch money closely, and work to reduce operating and maintenance costs. To handle these situations effectively, technicians must be trained and taught to cope with changing flow requirements. Knowing your stations and their characteristics are an absolute. Technicians must become familiar with the kind of equipment their station has, and its proper use. The goal here is to detail the appropriate methods and equipment required to handle these tasks.
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Document ID:
835A153E
Design Of Distribution Metering And Regulating Stations
Author(s): Edgar Wallace Collins
Abstract/Introduction:
The design of natural gas distribution metering and/or regulating stations is a mixture of science and art, or knowledge and judgment. The process requires four areas of knowledge: product, application, components, and communication. The goal in design is to use judgment to select and combine compatible components to create an effective, safe, and economical unit.
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Document ID:
96FB0CDC
Determination Of Leakage And Unaccounted For Gas - Transmission
Author(s): Rick Tompkins
Abstract/Introduction:
The search for Lost and Unaccounted-for Gas (LAUF) has been a priority for pipeline companies for many years. As an industry, we have an incredible depth of knowledge in how to measure and account for natural gas. However, the successful outcome of a LAUF study sometimes requires fresh eyes. It is not unusual to find people that know the answer to the problem, but having looked at it for so long they have become blind to the fact they have a problem. This paper will highlight some of the ways the industry should be approaching the determination of LAUF by looking at: Review of the Tariff Review and Verification of Audited Volume Statements Interviewing Technicians Analyzing the Measurement Processes Meter Testing and Inspection Reporting and Recommendations
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Document ID:
73A11554
Effects And Control Of Pulsation In Gas Measurement
Author(s): Robert J. Mckee
Abstract/Introduction:
Accurate gas measurement has always been important in the Natural Gas Industry and is even more essential in todays operating environment. Flow meters not only determine how much energy is bought and sold but how much a transportation company is paid for moving gas. One of the most common measurement errors and the most difficult to identify in metering is that caused by pulsating flow. Pulsating flow can be problematic for essentially all types of gas meters. It is important to understand the effects that pulsation has on the common types of flow meters used in the gas industry so that potential error-producing mechanisms can be identified and avoided. It is also essential to understand pulsation control techniques for reducing pulsation effects. This paper describes the effects of pulsation on orifice, turbine, ultrasonic, and other meters used in the industry. It also presents information and suggestions on how to mitigate pulsation effects at meter installations, including a specific procedure for designing acoustic filters that can isolate a flow meter from the source of pulsation.
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Document ID:
A1DBB8F3
Effects Of Abnormal Conditions On Accuracy Of Orifice Measurement
Author(s): Dean Graves
Abstract/Introduction:
Whenever one focuses on gas or fluid measurement, he or she will eventually discover an abnormal condition at a measurement station. Invariably someone will ask, What effect will it have on measurement? A student of measurement may spend years answering this question. This and similar questions have generated many research studies. This research has enabled us to better understand measurement abnormalities and to improve measurement procedures and standards. Even though we have made great strides in measurement, we will continue to ask this question. It is this question that has led to the development of this paper. Instead of focusing on certain specific abnormalities, this paper addresses the overall subject of measurement abnormalities and presents some investigative tools for the reader as they attempt to answer this question. However, before we can understand measurement abnormalities, it is important to review proper or accurate measurement.
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Document ID:
B19E630F
Fundamentals Of Gas Measurement
Author(s): Douglas E. Dodds
Abstract/Introduction:
To truly understand gas measurement, a person must understand gas measurement fundamentals. This includes the units of measurement, the behavior of the gas molecule, the property of gases, the gas laws, and the methods and means of measuring gas. Since the quality of gas is often the responsibility of the gas measurement technician, it is important that they have an understanding of natural gas chemistry.
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Document ID:
6653C544
Fundamentals Of Gas Measurement
Author(s): James W. Keating
Abstract/Introduction:
Gas measurement people are concerned with gas laws. To become proficient in all phases of gas measurement, one must fully understand what natural gas is and the theory of its properties. The theories about natural gas properties are the gas laws and their application is essential to natural gas measurement. Quantities of natural gas for custody transfer are stated in terms of standard cubic feet. To arrive at standard cubic feet from actual flowing conditions requires application of correction factors that are defined by the gas laws.
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Document ID:
4A3642D3
Fundamentals Of Gas Turbine Meters
Author(s): Tom Hudson
Abstract/Introduction:
Gas Turbine Meters were introduced to the US in the 1960s. Since their introduction the turbine meter has grown in popularity due the fact that they have a high degree of accuracy, repeatability and the ability to cover a large flow range. Gas turbine meters are available with an assortment of configurations, gear driven odometers, ID drives, fully electronic designs with a variety of outputs and self-correcting models. Many new and imaginative developments have been added to the turbine meter. This greatly improves the diversity of the meter and allows for the meter to be used in new flow measurement applications. The smaller gas turbine meters have been used to replace rotary and larger diaphragm meters. Larger turbine meters are used in city gates, power stations, gas storage fields or to replace orifice runs. The turbine meter is versatile and accurate over a wide range of flowing conditions making it the preferred choice as a reference for several calibration facilities. The turbine meter provides less pressure drop for equivalent flow rates when compared to other types of meters. This means the gas in a pipe line can be moved more efficiently. The meter can also provide pulse outputs allowing it too easily be interfaced with a variety of flow computers, correctors and local readout devices.
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Document ID:
571ED90E
Installation And Operation Errors In Gas Measurement
Author(s): Thomas B. Morrow, Edgar B. Bowles
Abstract/Introduction:
Installation errors may occur when an instrument is used in a manner different from how it was calibrated. For example, suppose that a temperature sensor is calibrated in a stirred, constant temperature bath. During calibration, the sensor is in thermal equilibrium with the circulating fluid, and the fluid and sensor temperatures are the same. However, let the same sensor be used to measure the temperature of gas flowing through a pipe at low velocity. If the pipe wall temperature is different from the flowing gas temperature, convection heat transfer will occur between the gas and the pipe wall, radiation heat transfer between the pipe wall and the sensor, and convection heat transfer between the sensor and the flowing gas. The sensor is not in thermal equilibrium with the flowing gas and the sensor temperature will be different from the flowing gas temperature. Flow meter installation errors can occur when a meter is calibrated in one piping configuration, and then is used in a different configuration. Installation errors often occur when the flow meter measurement is sensitive to the shape of the gas flow velocity profile. Between 1980 and 2005, considerable research was performed to better understand the magnitude and direction of installation errors for orifice meters, turbine meters, and ultrasonic meters. The research results were critically reviewed by industry measurement standards committees, and served as the basis for affirmation or revision of the installation specifications. This paper reviews some types of installation and operation errors found for orifice meters, gas ultrasonic meters, and turbine meters.
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Document ID:
B6AA4704
Low Pressure Gas Measurement Using Ultrasonic Technology
Author(s): Volker Herrmann, Toralf Dietz, Sick Maihak
Abstract/Introduction:
The acceptance of ultrasonic metering as a cost effective form of measurement has grown dramatically over the past 10 years. A growing portion of this market is in custody transfer applications. This growth is primarily due to growing acceptance in industry, advances in the technology, extensive self diagnostic capabilities and industry /regulatory standards and recommendations related to their use in custody transfer applications. With the research and development which has been completed to date, ultrasonic meter use in domestic /residential and high pressure applications has been proven and has widespread acceptance. New research and development is being done to address the segment of the market which poses additional challenges in the use of this technology. This is the use of these meters in atmospheric and low pressure applications such as gas distribution systems, and industrial fuel gas measurement.
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Document ID:
762F76D1
Mass Meters For Gas Measurement
Author(s): Karl Stappert
Abstract/Introduction:
Coriolis meters have gained worldwide acceptance in liquid applications since the early 1980s with an installed base of more than 400,000 units. Newer designs have increased low-flow sensitivity, lowered pressure drop, and increased noise immunity enabling performance characteristics that are similar or better than traditional metering technologies. Coriolis also has attributes that no other fluid measurement technology can achieve. Some of these attributes are the meters immunity to flow disturbances, fluid compositional change, and it contains no wearing parts. With more than 25,000 meters measuring gas phase fluids around the world, many national and international measurement organizations are investigating and writing industry reports and measurement standards for the technology. In December of 2003 the American Gas Association and the American Petroleum Institute co-published AGA Report Number 11 and API Manual Petroleum Measurement Standards Chapter 14.9, Measurement of Natural Gas by Coriolis Meter.
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Document ID:
54A73C4B
Multipath Ultrasonic Flow Meters For Gas Measurement
Author(s): John Lansing
Abstract/Introduction:
The use of ultrasonic meters for custody (fiscal) applications has grown substantially over the past several years. This is due in part to the release of AGA Report No. 9, Measurement of Gas by Multipath Ultrasonic Meters Ref 1, Measurement Canadas PS-G-E-06 Provisional Ultrasonic Specification Ref 2, and the confidence users have gained in the performance and reliability of ultrasonic meters as primary measurement devices. Just like any metering technology, there are design and operational considerations that need to be addressed in order to achieve optimum performance. The best technology will not provide the expected results if it is not installed correctly, or maintained properly. This paper addresses several issues that the engineer should consider when designing ultrasonic meter installations.
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Document ID:
79950E22
Fundamentals Of Orifice Metering
Author(s): Bob Carlson
Abstract/Introduction:
Throughout the oil and gas industry, there stems the need for accurate and economical measurement of process fluids and natural gas. Orifice Meters, sometimes referred to as Orifice Fittings, satisfy most flow measurement applications and are the most common flow meter type in use today. The Orifice Meter, sometimes also called a head loss flow meter, is chosen most frequently because of its long history of use in many applications, versatility, and low cost, as compared to other available flow meter types.
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Document ID:
C09218C7
Orifice Meter Maintence And Operation
Author(s): Scott Smith
Abstract/Introduction:
The natural gas industry has seen many changes lately. The world population is increasing and with this the energy demands in the world are also increasing. Producers and pipeline companies have seen tremendous growth and reorganization through these increased demands for energy. The advances in technology in the last decade have put a computer and cellular phone at everyones fingertips literally and increased the need for electricity, thus the need for natural gas to generate this electricity. With this increased demand for natural gas, the logistics involved in acquiring it, and the profit differential between these two, the need for proper maintenance is more important than ever.
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Document ID:
710178F6
Problems Unique In Offshore Gas Measurement
Author(s): David Wofford
Abstract/Introduction:
First, we need to clear up a few common misperceptions. Measurement is Measurement is Measurement. Natural gas compounds dont think, metering and analytical systems dont care whether they are over water or dirt, and measurement standards are not only relevant to specific time zones. These are not intellectual beings that choose to exhibit behaviors based upon geography, culture, socioeconomics, political doctrine or the pursuit of spiritual fulfillment. Hydrocarbons are Hydrocarbons, Meters are Meters and Standards are Standards. Natural gas behaviors are defined within the laws of chemistry and physics. When hydrocarbons are extracted from the Earth, heated, cooled, filtered, swirled, separated, condensed, compressed, expanded, processed, refined, transported via a pipeline and quantified by a metering system, the hydrocarbon compounds dont care whether they are in the snow covered Rockies, windy West Texas, sunny Southern California or a hundred miles out to sea in the Gulf of Mexico. Hydrocarbon behaviors are non-discriminatory just equal opportunity combustible molecular structures seeking physical equilibrium in a man made world of cylindrical manipulation and containment.
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Document ID:
0652C0FE
Thermometry In Gas Measurement
Author(s): Joshua J. Kinney
Abstract/Introduction:
There are many conditions in natural gas flow measurement that can cause errors that are difficult to pinpoint. Finding inconsistencies in large measurement systems is cumbersome, especially if the base measurements are in error. Accurate flow measurement requires the base measurements to be reported correctly, including gas temperature. When temperature is measured incorrectly, it can have a pronounced effect on overall flow measurement.
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Document ID:
B7F1BD93
Wet Gas Measurement
Author(s): Richard Steven
Abstract/Introduction:
Demand for wet gas flow measurement technologies has been increasing steadily for many years. As natural gas wells age the once dry natural gas production flow becomes wet natural gas as the dynamics of the reservoir change. Furthermore, with the value of hydrocarbon products rising steadily, reservoirs that were once considered not profitable, or marginal, are being produced. These marginal fields often produce wet gas flows from the outset. It is essential that these wet gas flows are metered as accurately as possible. The traditional method of metering wet gas or multiphase flows is to separate the fluids in a dedicated separator vessel. The inlet of these vessels receives the unprocessed flow of natural gas and liquids (which may be both hydrocarbon liquids and water). The vessel is designed to separate the component fluids and allow the flow to exit separately as natural gas and single component liquid flows where single phase flow measurement technologies can be utilized. This is the original wet gas and multiphase meter technology.
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Document ID:
C85B2B0D
Contaminant Accumulation Effect On Gas Ultrasonic Meters
Author(s): John Lansing
Abstract/Introduction:
During the past several years the use of ultrasonic meters (USMs) has gained world-wide acceptance for fiscal applications. The many benefits of USMs have been documented in several papers at virtually every major conference. As the cost of gas continues to increase, the importance of knowing that the ultrasonic meter is operating accurately has never been more important. The use of diagnostics to help identify metering issues has been discussed in several papers over the past few years Ref 1 & 2. The traditional method of verifying whether the USM is operating accurately essentially requires using the USMs diagnostic information to help understand the meters health. This has often been referred to as Condition Based Maintenance, or CBM for short. Different USM meter designs require different analysis techniques, especially for the velocity profile analysis. For the field technician, it is often difficult to understand all the diagnostic features of each USM meter design. Through the years software has been developed to help determine if the meter is operating correctly or not. However, it is still very difficult to clearly define limits on some of the diagnostic parameters that translate into a quantifiable metering error.
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Document ID:
33F33999
Application Of Densitometers To Liquid Measurement
Author(s): Mike Pritchard
Abstract/Introduction:
This paper discusses the types of density meters in common use in the petrochemical / oil and gas industry, their advantages and disadvantages. It then deals more specifically with the vibrating element density meters and their general uses. The paper concludes with specific liquid applications in crude oils, refined products, liquefied gases, etc. This paper is not a grand opus, but deals with basic terms usage and rules of thumb regarding density measurement in real process applications.
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Document ID:
D7D6D5E9
Application Of Turbine Meters In Liquid Measurement
Author(s): Jack Heath
Abstract/Introduction:
Liquid driven turbine type devices have been used in a variety of applications, including liquid measurement, for centuries. Water wheels were employed by the Romans, and before that the Chinese had water driven clocks. Rotating water driven devices have long been used to power grain mills. Today much of the worlds electricity is generated by liquid turbines in hydroelectric dams. Simply put, a liquid turbine device takes flowing fluid to turn a vaned or helical rotor in proportion to flow rate. The topic of this discussion will be the application of turbine meters in liquid measurement. Turbine meters are flow velocity measuring primary devices. Meters similar to those in service today have been used since the early 1900s. Initially the spinning rotor was connected to a mechanical totalizer by a gear and wiggler mechanism extending out of the meter body. This kind of design predominated until the 1960s as advances in electronics began to enable the use of electromagnetic pickup coils as non-contact rotor speed sensors. Elimination of mechanical drag improved low flow measurement capability and removed a potential for leaking. Electronic displays increasingly provide more capability and lower maintenance than mechanical devices.
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Document ID:
B457DD44
Automated Truck Loading Systems
Author(s): Jason Casilio
Abstract/Introduction:
The loading of petroleum products at truck loading terminals has undergone a great deal of renovation since the early 70s. These changes, for the most part, have taken place due to the introduction of electronic instrumentation and control devices, which replaced what was traditionally mechanical equipment at the load rack. Through the 80s and into the early 90s this equipment has been refined and its features expanded to meet the needs of modern truck loading facilities. The electronic preset is responsible for much of this improvement, and while product accountability, reduced operating cost and improved inventory control continue to be one of the significant benefits of the electronic preset, government regulations have also had a large impact on the upgrading effort. The Clean Air Act, which many major metropolitan areas comply with, legislates regulations requiring a certain percentage of oxygenates in the gasolines sold in their area. These regulations may prohibit the petroleum products from being directly delivered in their refined form, and may require that they be blended with products such as Ethanol (gasoline) or Biomass (diesel). Combining this with the requirements of mid-grade and higher performance type gasolines for todays fuel-efficient automobiles, the blending requirements start to multiply. (Blending is now required to range anywhere from 99.9/.1 % up to 50/50 % which requires complete flexibility of blending at the load rack.) The scope of this paper will focus on the requirements for blending and how todays electronic preset will meet the challenge by offering a number of blending solutions, the sequential blender, the ratio blender, the side stream blender, and the hybrid blender.
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Document ID:
1C8341BD
Calculation Of Liquid Petroleum Quantities
Author(s): Peter W Kosewicz
Abstract/Introduction:
In the Petroleum industry as hydrocarbons are purchased, sold or transferred there are two key elements that must be determined. These elements are the quantity and quality of the hydrocarbon in question. This paper will address one of those elements, the determination of the quantity of the hydrocarbon in the transaction. The determination of the quantity of hydrocarbon can be further subdivided into: Static quantity determination and Dynamic quantity determination Static quantity is determined when the hydrocarbon is measured under non-flowing conditions, such as when contained in a tank, rail car, truck or vessel. Conversely Dynamic quantity determination occurs when the hydrocarbon is measured under flowing conditions.
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Document ID:
42F7251B
The Calibration Of Storage Tanks
Author(s): Michael J Yeandle
Abstract/Introduction:
This paper will discuss several field measurement methods that are presently in use to calibrate upright, above ground, cylindrical, cone and floating roof steel storage tanks. Tank calibration is often referred to as tank strapping due to the original method of placing metal straps around wooden containers used for the storage of oils. Over the years, as the price of crude oil and petroleum products has increased, storage facilities, and the accurate measurement of oil in storage, has become very important. Today we have storage tanks as large as 1,500,000 barrels in volume and therefore, one can see how important the accurate calibration of a storage tank can be. Any errors made at the calibration stage will cause errors in the final tank table.
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Document ID:
544F3392
Crude Oil Blending
Author(s): Kevin B. Macdougall
Abstract/Introduction:
There are a number of applications that require blending of crude oil or other hydrocarbons and they include transportation needs, pipeline capacity, product value and refining efficiency. Crude oil blending is accomplished by two methods: on-line blending and tank blending. On-line Blending In this method two or more components are injected from separate pipelines and are mixed in a single line. Ensuring adequate mixing is a necessity and often requires some type of in-line static mixer or mechanical mixing device. The use of piping elements alone may not provide adequate mixing. The efficiency of this method will depend upon the resulting streams Reynolds number, the type and number of piping elements, and the time allowed for mixing. With either method, the use of an injection quill for the smaller of the two streams will assist in mixing.
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Document ID:
777D6F59
Crude Oil Gathering By Truck Metering Versus Manual Gauging
Author(s): J. W. Sulton
Abstract/Introduction:
Normal procedures for custody transfer of oil from lease tanks requires the driver/gauger to manually gauge the producers storage tank to determine the volume of oil in the tank and the S&W content of the oil. This procedure requires the driver to climb to the top of the tank where exposure to H2S or injury from falling from the tank is a risk. This paper will compare the manual method of tank gauging as described in API Chapter 18, Section 1 to the use of a measurement system that is mounted on the transport truck. The truck mounted measurement system relates to a system and a method for measuring crude oil, and more particularly to a system for accurately measuring oil as it is transferred from a lease storage tank to a transport vessel.
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Document ID:
92C429EF
Design, Operation & Maintenance Of L.A.C.T. Units
Author(s): Glen E. Meador, Ken Steward
Abstract/Introduction:
The two most common methods of measuring the volume of petroleum liquids are tank gauging and liquid metering. The problems associated with tank gauging are (1) it requires that an operator make an accurate liquid level determination by climbing to the top of the tank to be gauged, (2) that an operator make an accurate average liquid temperature determination, (3) that an operator make an accurate sediment and water content analysis and (4) that the tank be static, which means that no liquid can enter or leave the tank during gauging. Once the contents of the tank are removed, it is necessary to regauge the tank. Since crude oil is sold on the basis of temperature, API Gravity and the amount of Basic Sediment and Waste (BS&W), it is very important to make accurate measurements. The greatest effect on volume is temperature - typical crude oil will expand and contract at the rate of 2% per 40 F temperature change.
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Document ID:
493C4E14
Displacement Meters For Liquid Measurement
Author(s): R. Gary Barnes
Abstract/Introduction:
This paper will examine the strengths and weaknesses as well as design principles that are fundamental to capillary seal PD Meters. It will also highlight the system and the parameters that must be considered before accurate meter selection can be made. Comparisons will be presented utilizing the six (6) most common PD Meter principals: (1) Oscillating Piston, (2) Sliding Vane, (3) Oval Gear, (4) Tri-Rotor, (5) Bi-Rotor, (6) Nutating Disc.
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Document ID:
73783AD0
Effects Of Flow Conditioning On Liquid Measurement
Author(s): James E. Gallagher
Abstract/Introduction:
The full cost of ownership consists of the initial capital, commissioning, training, spare parts, maintenance and calibration costs for the lifetime of the equipment. The full cost is several times the initial capital investment and should be the deciding factor in equipment selection. The technical selection - accuracy, repeatability, drift, ease of calibration as well as reliability indirectly affects the cost of ownership.
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Document ID:
B8ACE3D2
Effects Of Petroleum Properties On Pipeline Measurement
Author(s): James E. Gallagher
Abstract/Introduction:
Measurement is the basis of commerce between oil producers, royalty owners, oil transporters, refiners, marketers, governmental authorities and the general public. In fact, accurate measurement of hydrocarbon fluids has a high impact on the Gross National Product of exporting and importing countries, the financial performance and asset base of global companies, and the perceived efficiency of operating facilities. An understanding of the process (operating and fluid) conditions, as well as, the physical properties of the hydrocarbon fluids are fundamentally important before designing or analyzing measurement facilities. For simplicity, we will limit our treatise to dynamic measurement applications. Several methods and types of equipment are utilized to achieve accurate measurement. The basic measurement process remains the same --- the act of comparing a known mass quantity to an unknown mass quantity.
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Document ID:
80C49D29
Polymer-Grade Ethylene Measurement
Author(s): Henry James, Steve Martindale
Abstract/Introduction:
An ethylene transportation system consists of a pipeline network and salt dome storage facility linking producers and consumers. Since producers and consumers are not equipped with on site storage, the systems are designed with maximum flexibility to satisfy the continually changing demands of the operations (Figure 1). Ethylene pipeline and storage systems are operated in either the gaseous or dense phase fluid region. Systems designed prior to the mid 1970s were designed to operate in the gaseous fluid region and comply with DOT regulations for gas pipelines. Systems designed over the last two decades were designed to operate in the dense phase region for several reasons - lower transportation cost, lower metering cost and compliance with the DOT HVL regulations.
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Document ID:
B4AD1A44
Evaporation Loss Measurement For Storage Tanks
Author(s): Warren A. Parr, Jr.
Abstract/Introduction:
In the 1950s hydrocarbon evaporation loss from storage tanks was studied to develop emission estimating equations. At that time, the primary driver for knowing the evaporation rate was system loss control. During the early 1990s, the US Environmental Protection Agency (EPA) began programs for stricter record keeping and reduction of storage tank emission. This forced industry to scrutinize the accuracy of existing evaporation loss estimating equations and to develop improvements to various tank appurtenances in an effort to lower hydrocarbons emissions. Much of the EPA activity was focused on floating roof tanks. This paper will review: Sources of emissions from floating roof tanks Research and development to improve emission loss equations Testing of existing fittings Testing of design improvements to lower emissions Development of EPA approved test protocol for improved equipment designs Future areas of emission research in floating roof tanks
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Document ID:
B55E25BE
Fundamentals Of Liquid Measurement - Part 1
Author(s): David Beitel
Abstract/Introduction:
Correct measurement practices are established to minimize uncertainty in the determination of the custody transfer volume (or mass) of products. Understanding and evaluation of the fundamental cause and effect relationships with the liquid to be measured will lead to a volume determination that most closely matches the true volume at the referenced standard pressure and temperature. When designing a new measurement station it is up to us as measurement people, to understand the product to be measured, apply the correct equipment, and implement the appropriate correction equations.
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Document ID:
9F3CFEA0
Fundamentals Of Liquid Measurement II
Author(s): Doug Arrick
Abstract/Introduction:
Measurements of liquid petroleum can be performed with the liquid in a static or dynamic state. Custody measurements are made in both states. Static measurements of petroleum liquids are made with the liquid in a tank. This paper will discuss the steps required to calibrate, gauge and sample tanks. These are the steps necessary to measure liquid petroleum in a static state.
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Document ID:
85C857BB
Fundamentals Of Liquid Measurement III - Dynamic
Author(s): Peter W Kosewicz
Abstract/Introduction:
Weve learned when measuring crude oil or any hydrocarbon that liquids expand and contract with increases and decreases in temperature. The liquid volume also decreases when pressure is applied. All these effects are part of the physical properties of liquid petroleum fluids. We learned in Fundamentals of Liquid Measurement I how these physical properties effect the measurement of liquid hydrocarbons. The objective of either static measurement or dynamic measurements is to determine the quantity and quality of hydrocarbons transferred. However these measurements are rarely performed at the standard conditions discussed in Fundamentals I, therefore not only must temperature be measured, but also density, sediment and water, vapor pressure, pressure and viscosity must be measured. With these measurements correction factors such as Volume Correction Factors (VCF) can be determined to allow volumes determined at operating conditions to be expressed at standard reference conditions.
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Document ID:
E5A05005
Fundamentals Of Liquid Turbine Meters
Author(s): Herb Decker
Abstract/Introduction:
In this class we will review the theory, operation and characteristics of the helical turbine meter and why it performs so well in difficult applications. The Helical Rotor turbine flow meter is an outgrowth of the flat bladed turbine that has been in service for many years, and offers significant performance advantages. These advantages are seen in crude oils, multi-viscosity and other problematic flow measurement applications. Helical turbines have been used in crude services up to 500 cSt in standard applications and over 800 cSt in special applications. In the area of multi-viscosity applications helicals operate over very wide ranges. Helical turbine meters will operate at specification over viscosities from 0.6 to 160 cSt and above with a single meter factor.
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Document ID:
ACA329D6
Gauging, Testing And Running Of Lease Tanks
Author(s): Jane Williams
Abstract/Introduction:
Many production sites do not have metering facilities for custody transfer. Metering facilities require additional capital expenditures but minimize the labor costs over the life of the lease. If metering is not available at the field location the custody transfer measurement is generally performed by manual tank gauging. In this case, after gauging the tank can be emptied into a truck or into a pipeline. Another method which is used occasionally is to have a meter on the truck which serves as the custody transfer. However, the majority of locations which do not have a LACT (Lease Automatic Custody Transfer) Unit utilize the tank gauge as the means of custody transfer. The procedure for gauging of tanks is covered by API (American Petroleum Institute) MPMS (Manual of Petroleum Measurement Standards) Chapter 3. Verification of the equipment utilized in the gauging process against certified test standards which are traceable to the NIST is now required.
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Document ID:
8069FDF2
Helical Turbine Meters For Liquid Measurement
Author(s): Jim H. Smith
Abstract/Introduction:
Turbine meters have been used for the custody transfer of refined petroleum products and light crude oils for over 35 years. When correctly applied, they offer high accuracy and long service life over a wide range of products and operating conditions. Traditionally, turbine meters were used for the measurement of low viscosity liquids and positive displacement meters for higher viscosity fluids. However, new developments in turbine meter technology are pushing these application limits while increasing reliability and accuracy. This paper will examine the fundamental differences between conventional and helical turbine meter measurement. It will also discuss new developments in flow conditioning, helical meter proving and viscosity compensation to extend turbine meter application limits.
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Document ID:
D5173AED
Installation And Operation Of Densitometers
Author(s): Don Sextro
Abstract/Introduction:
A densitometer is an on-line and continuous device used to measure the density of a flowing stream. In the oil and gas industry, a densitometer is normally used to measure the density of liquid hydrocarbon finished products like propane and gasoline and liquid mixtures like Y-grade natural gas liquids (NGL), but can also be used to measure the density of crude oil. The typical installation is in a single-phase liquid stream, but densitometers can be used to measure single-phase gas or vapor. This paper addresses only continuous, on-line liquid density measurement. There are a number of applications in the oil and gas industry where measured density is important. First, and probably the most widely used, is to determine the quantity of material passing through a meter. The quantity may be determined either through mass or volumetric measurement techniques, each using the measured density but applying it to the final quantity in a different way. A second use is to detect a pipeline interface, the plug of liquid between two dissimilar products shipped in the same pipeline. Continuous, on-line density measurement provides a pipeline operator with the ability to see the density change from one batch to the next and make the appropriate valve changes to properly route liquids to the correct destination. Another common use is in pipeline leak detection where operators look for relatively small leaks by comparing pressures and flow rates at points along a pipeline. Measured density can provide a more accurate prediction of frictional pressure loss in the pipeline since, in addition to flow rate, pressure loss is a function of the Reynolds number which is in turn a function of the fluid density. Lastly, measured density can also provide meaningful data for quality monitoring of finished products and other fluids.
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Document ID:
18DFDB44
Liquid Measurement Field Surveys
Author(s): C. Stewart Ash
Abstract/Introduction:
What is a Liquid Measurement Field Survey? Isnt that just another name for an Audit? In the Oil Industry, the two are often considered to be the same. There are indeed similarities between the two, but there are also distinct differences. An Audit is usually conducted by an Auditor either from the corporate internal audit group or from an external independent auditing company. This type of audit is an official examination and verification of accounts and records to assure that adequate control is provided for company assets. It is a review to assure that established procedures are followed, calculations are done correctly, and the accounting process is correct and current. A Measurement Survey is a review of field facilities and operations usually conducted by either in-house measurement specialists or qualified outside consultants. The purpose of the survey or review is to ensure the proper equipment is used, the equipment is installed in accordance with the manufacturers and/or industry guidelines, proper measurement procedures are followed, and personnel are properly trained.
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Document ID:
E0F9E616
Liquid Measurement Station Design
Author(s): Michael Frey
Abstract/Introduction:
The industry continues to benefit from advancements in metering technologies, instrumentation and computer control systems applied to liquid measurement equipment. These advancements result in increasingly complex and sophisticated requirements for interfacing with the mechanical equipment. Complete compatibility of the instrumentation system with the metering components must be incorporated in the design to assure optimum functionality of the system.
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Document ID:
CF45F562
Marine Crude Oil Terminal Measurement Systems
Author(s): Harold E. Osborn
Abstract/Introduction:
In this paper we will discuss the different types of measurement systems used at crude oil terminals, the requirements of these systems and why they are important.
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Document ID:
3362E146
Mass Measurement Of Natural Gas Liquid Mixtures
Author(s): Eric Estrada
Abstract/Introduction:
The purpose of this paper is to review methods for directly or indirectly determining the mass of Natural Gas Liquid (NGL) streams. NGLs by definition are hydrocarbons liquefied by gas processing plants containing ethane, propane, butane, and natural gasoline.
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Document ID:
020B1554
Coriolis Meters For Liquid Measurement
Author(s): Marsha Yon
Abstract/Introduction:
A meter utilizing the Coriolis force to measure mass flow was first patented in 1978. Today, hundreds of thousands of Coriolis meters are in service in the hydrocarbon industry to measure both mass and volume of a wide variety of fluids. The American Petroleum Institute published Chapter 5.6 entitled Measurement of Liquid Hydrocarbons by Coriolis Meters in October 2002. This standard describes methods to achieve custody transfer levels of accuracy when a Coriolis meter is used to measure liquid hydrocarbons. This paper will review the technology and convey differences in Coriolis meters and mechanical meters in an attempt to clarify some of the issues surrounding the use of Coriolis meters especially for custody transfer in the petroleum industry.
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Document ID:
D90931A8
Measurement Accuracy And Sources Of Error In Tank Gauging
Author(s): C. Stewart Ash
Abstract/Introduction:
Tank gauging is the means used to determine the quantity of oil contained in a storage tank. How the volume is to be used often determines the degree of desired accuracy. If the volume is to be used to quantify a custody transfer movement and money will change hands based on the result, a high degree of accuracy is required but if the volume is to be used only as an operational tool (i.e., is the tank nearly full or nearly empty), a high degree of accuracy is usually not required. If the volume is to be used for inventory control and/or stock accounting, the desired accuracy would be less than for custody transfer but greater than for normal operations. The volume contained in a tank can be determined either by manually gauging the tank or by using an automatic gauging system installed on the tank. Hand gauging of tanks has normally been considered a very accurate method to determine the quantity of oil transferred into or out of a tank. In the United States, most automatic gauging systems have been considered to be less accurate than hand gauging, but there are automatic tank gauging systems available that meet the requirements for custody transfer.
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Document ID:
2DE89EAB
Shrinkage Losses Resulting From Liquid Hydrocarbon Blending
Author(s): J. H. James
Abstract/Introduction:
Pipeline integrity balance and custody transfer accuracy have been the focus of measurement specialists since the industry began trading and transporting liquid hydrocarbons. Even with the best volumetric measurement equipment, unaccounted for discrepancies still were occurring. Temperature, pressure and meter factor corrections were not enough to explain these discrepancies. Mathematicians have been telling us for centuries that one plus one equals two. In an ideal world of Newtonian physics this is the case but in the world of volumetric hydrocarbon measurement one plus one is usually less than two. However it can, in rare circumstances be greater than two. As stated in the Dec. 1967 edition of API Publication 2509C regarding the result of blending two different hydrocarbons, If the nature of the molecules of the components differ appreciably, then deviation from ideal behavior may be expected. This deviation may either be positive or negative that is, the total volume may increase or decrease when components are blended. .. Inasmuch as petroleum components contain molecules of various sizes and weights, solutions of two separate components are seldom ideal. Consequently it is to be expected there may be a change in volume associated with the mixing or blending of petroleum components of varying gravities and molecular structure. In liquid petroleum blending however, the result has always been shrinkage. In this paper, only the negative deviations or losses will be addressed.
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Document ID:
53C7ED47
Measurement Methods For Liquid Storage Tanks
Author(s): Robert Arias
Abstract/Introduction:
This paper will provide, in general terms, an overview of the different technologies available to measure Net Standard Volumes in storage tanks. The Net Standard Volume (NSV) is used as the primary unit of measurement for custody transfer and/or Inventory Control. The Net Standard Volume (NSV) documents the agreement between the representatives of the interested parties (custody transfer) of the measured quantities and qualities of the transferred liquid.
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Document ID:
79324778
Measurement Of Petroleum On Board Marine Vessels
Author(s): John A. Szallai
Abstract/Introduction:
Generally, marine measurements are used to confirm the validity of shore side custody transfer measurement. Marine measurements can also be used for custody transfer if no other valid means are available or the shore side custody transfer system is not available or functioning properly. Measurement of petroleum on board marine vessels, ocean or inland, are generally based on the American Petroleum Institutes Manual of Petroleum Measurement Standards, Chapter 17, with cross references to other pertinent chapters. The actual physical measurement of petroleum on board marine vessels is not vastly different than for a shore tank. The differences arise from the fact marine vessels are floating structures that are mobile. Their physical structure permits them to change their orientation relative to a flat plain. This movement requires additional steps be taken and different adjustments be made to the physical measurements in order to obtain the proper volumes.
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Document ID:
467BD463
Orifice Meters For Liquid Measurement
Author(s): Zaki D. Husain
Abstract/Introduction:
According to Webster dictionary, orifice is a mouth like aperture and meter is an instrument that measures. So, orifice meter is a circular opening in a pipe that measure. In early 1600 Castelli and Tonicelli were first to state that the velocity through a hole in a tank varies as square root of water level above the hole. They also stated that the volume flow rate through the hole is proportional to the open area. It was almost another century later in 1738, a Swiss physicist Daniel Bernoulli developed an equation that defined the relationship of forces due to the line pressure to energy of the moving fluid and earths gravitational forces on the flowing fluid. Bernoullis theorem has since been the basis for flow equation of flowmeters that expresses flow rate to differential pressure between two reference points. Since the differential pressure can also be expressed in terms of height or head of liquid above a reference plane, a differential-pressure type flowmeter is often called Head-type Flowmeter.
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Document ID:
456AF0F7
Pycnometer Installation, Operation And Calibration
Author(s): Marion Haynes
Abstract/Introduction:
The accurate calibration of density meters depends on the correct procedures installation and operation of a certified pycnometer. Because this instrument is normally used in hydrocarbon service, the installation design and safety concerns in the operation and calibration of the pycnometer is paramount.
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Document ID:
4B4B0EB8
Resolving Liquid Measurement Differences
Author(s): Herbert H. Garland
Abstract/Introduction:
What is a custody transfer? It is the volume of liquid moved multiplied by the tariff, which equates to ! It is the bottom line, which is the cash register. Is your companys cash register running over or short? What is the percentage it is off? To minimize liquid measurement problems, clear lines AUTHORITY and RESPONSIBILITY must be established and accepted. Established by management and accepted by the employee(s) assigned this role. To adequately perform loss/gain tracking and analysis you must be able to RECOGNIZE that a problem exists. More often than not we tend to think it is the other person or company that has the problem. It is a matter of admitting you may have the problem instead of the others. Check your equipment and procedures first. DETERMINE what is causing the problem. Is it an error in procedure, equipment failure, malfunction or a calibration problem? Or is it human error? When this has been determined, you can then CORRECT the problem.
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Document ID:
93F8BDFC
Troubleshooting Liquid Pipeline Losses And Gain
Author(s): Joseph T. Rasmussen
Abstract/Introduction:
Todays pipelines are multi-dimensional systems providing multiple services for many shippers and customers. Pipeline systems may connect multiple origins and destinations, and carry various products across long distances with changing profiles, pipe dimensions and directions. Monitoring pipeline losses and gains employs tools and analysis methods developed specifically to troubleshoot pipeline variances. Examination of pipeline losses and gains uses basic statistical tools as well as intuitive and creative insight into what controls losses and gains. The basic tool for evaluating system performance is Loss/Gain, a measure of how well receipts, deliveries and inventory match up over a period of time. The concept is similar to that used for leak detection, but usually covers a longer time period. Loss/gain is a measure of the quality of the overall measurement in a system, and excessive loss/gain can signal the need for an investigation to identify causes and develop corrective actions. Good measurement can be enhanced by continuously monitoring the system, equipment and procedures to insure they are operating within acceptable limits. This monitoring may be accomplished by the use of Control Charts. This paper will review control charts and procedures, which may be used to monitor systems, and offers troubleshooting guides to use when a pipeline systems loss/gain is out of tolerance.
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Document ID:
13C3D2EC
Ultrasonic Meters For Liquid Measurement
Author(s): Christopher B. Laird
Abstract/Introduction:
The first significant application of ultrasonic technology for petroleum measurement was on the leak detection meters on the trans-Alaska pipeline. In this case, sections of the 48 pipe were fitted with ultrasonic transducers forming four chordal paths - see Figure 1. Twenty-three meters were installed along the 800-mile pipeline. These meters are still in service.
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Document ID:
D265DC3A
Viscosity And Its Application In Liquid Hydrocarbon Measurement
Author(s): Gary Rothrock
Abstract/Introduction:
The why and how of measuring viscosity in hydrocarbons. Why do you do it? The cost involved and the pros and cons of different ways of doing the measurement.
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Document ID:
C4D890A4
Measuring High Viscosity Liquids With Flow Meters
Author(s): Peter P. Jakubenas
Abstract/Introduction:
This paper will discuss effective methods for measuring high viscosity liquids with various types of flow meters.
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Document ID:
75E6463A
Proving Liquid Meters With Microprocessor Based Pulse Outputs
Author(s): Galen Cotton
Abstract/Introduction:
The advent of microprocessor driven flow meters in the late 1960s and early 1970s was heralded as a new frontier in flow measurement. Little did we anticipate the unintended consequence of adopting these new technologies or how our conventional verification techniques would be challenged by them. We are still playing catch-up in the realm of flow meter verification where manufactured or, computationally derived flow meter pulse outputs are concerned.
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Document ID:
878D92C9
Proving Liquid Ultrasonic Flow Meters
Author(s): Don Augenstein
Abstract/Introduction:
Ultrasonic transit-time flow meter (UFM) technology is now well over 50 years old. UFM improvements in transducer design, signal processing and more importantly, the understanding of factors that influence the performance of these meters have greatly improved these meters performance. Current UFMs achieve accuracy and reliability comparable to or better than older mechanical technologies (i.e., turbine and positive displacement meters) and are now challenging these traditional flow meters in hydrocarbon measurement applications. This transition is being driven by a number of UFM attributes including: High accuracy and high turndown ratio Availability of large size meters Non-intrusiveness Low maintenance costs Information on flow characteristics and fluid properties Excellent on-line diagnostics Applicability for extreme environments (from cryogenics of -170C to heated fluids +250C)
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Document ID:
DBF78DBD
Offshore Liquid Fpso Measurement Systems
Author(s): Terry Cousins
Abstract/Introduction:
Floating production, storage and offloading systems (FPSOs) receive crude oil from deepwater wells and store it in their hull tanks until the crude can be pumped into shuttle tankers or oceangoing barges for transport to shore. They may also process the oil and in some later FPSOs be used for Gas distribution. Floating productions systems have been utilized in remote offshore areas without a pipeline infrastructure for many years. However, they have become even more important with the push by the offshore industry into ever deeper waters. Floating production, storage and offloading/floating storage and offloading (FPSO/FSO) systems have now become one of most commercially viable concepts for remote or deep-water oilfield developments. They also allow a company to develop offshore resources quickly between discovery and production. They have been shown to reduce this time as much as two to four years. Further, there can be significant cost savings in developing marginal fields.
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Document ID:
1C2F85CD
Advanced Application Of Flow Computers And Telemetering Systems
Author(s): Jerry Van Staalduine
Abstract/Introduction:
For many years now, flow computers have been implemented in gas measurement systems to utilize technology, improve measurement accuracy, provide far more efficient data acquisition, and provide better control resources for remote interface through telemetry. As the meters functionality has increased, the meter technician has had to become more diverse in his or her knowledge of measurement, control, computers, and electronics. By taking a closer look at the various advanced applications and reviewing the basics, hopefully the technician will have a better understanding of the requirements of handling, installing, and working with todays advanced flow computers. Early on, the flow computer simply interfaced with the three primary inputs (differential pressure, static pressure, and temperature) required for gas measurement and duplicated the three-pen chart recorders measurements, but with improved accuracy and response.
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Document ID:
52A5DB05
Application Of Flow Computers For Gas Measurement And Control
Author(s): Don W. Griffies
Abstract/Introduction:
Flow Computers, like the computer industry, have been changing rapidly over the past few years. Faster, more powerful microprocessors, higher quality batteries and solar panels, improved electronics and new methods of remote communications now make it possible to automate field production and pipeline systems primarily using flow computers as the core hardware. Flow computers were originally designed to replace mechanical charts used in custody transfer gas measurement. They now are being used in whole scale SCADA systems often performing multi-tube and tube switching operations, flow control, tank monitoring, compressor monitoring, artificial lift and total MMBTU calculation. Software packages, both man machine interface and central data management and communications programs, have become powerful, efficient tools for operating, controlling and managing field production and pipeline systems. These systems are often integrated with sophisticated computer graphics programs to simplify monitoring and control operations throughout the computer networks. Advances in remote data communication enable companies to gain access to these sites to get current status, collect historical data and perform a host of control functions from the comfort of a field or home office.
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Document ID:
1FC8513D
Applications Of Portable Computers And Software
Author(s): Trey Thee
Abstract/Introduction:
The natural gas industry has undergone substantial changes over the last few decades. One of the largest changes has been in the way data is collected and stored. Laptops and PDAs are the most prevalent methods of data collection and storage in the field today. The use of these tools led to great leaps in productivity but in order for similar productivity increases to happen in the future and to maintain gains of the past, hardware and software must be chosen carefully. In this paper we will discuss mobile computing in the Natural Gas Industry.
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Document ID:
EF1A4568
Basic Applications Of Telemetering Systems
Author(s): Tommy Mitchell
Abstract/Introduction:
In a fast changing natural gas industry today it is important for companies to utilize all available technologies in order to safely operate and maintain a competitive edge in todays market place. One of many available technologies is telemetering. To understand telemetering let us first give a good definition of telemetering and how it applies to todays natural gas industry. Telemetering is defined as: The science of sensing and measuring information at a remote location and transmitting that data to a convenient location to be read and recorded. From this definition we can see that telemetering, as it applies to the natural gas industry, is simply a way to gather, read and record data remotely so it can be utilized. Some of the most common reasons companies install a basic telemetering system today are safety, increase production, improve operations efficiency, and monitor pipelines. However with todays advanced Flow Computers and RTU designs the reasons listed above can be easily achieved in most cases by installing one unit per location. It is the intent of this paper to cover basic telemetering principles as they apply to areas of the Oil and Gas Industry.
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Document ID:
C09843F9
Basic Electronics For The Field Technician
Author(s): Alexander R. Moore
Abstract/Introduction:
This paper has been prepared to give a basic overview of the electronic components within the oil and gas industry and how they function. Each unit of measure in this paper is named after experimenters in the field of electricity. The amp was named after Frenchman Andre M. Ampere. The volt was named after Italian scientist Alessandro Volta. And lastly the ohm, named after German scientist Georg Simon Ohm.
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Document ID:
03AA4012
Fundamental Principles Of Data Acquisition And Control Equipment
Author(s): Richard Cline
Abstract/Introduction:
This paper will address concepts of SCADA (Supervisory Control and Data Acquisition Systems) and their application to the measurement industry. An important focus of the paper is to provide the reader with an understanding of the technology and with guidelines to be used to evaluate this equipment as part of an automation project.
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Document ID:
EF597FA5
Communication Systems For Gas Measurement Data
Author(s): Clay Danley
Abstract/Introduction:
The key to building a reliable communications system starts with a path study using Global Positioning System coordinates gathered from each location where the measurement equipment is located. The path study will aid in determining the best communications technology necessary to get reliable data back to the host server. Some of the most widely used communications technologies are non-licensed Spread Spectrum radio, licensed MAS radio, GSM, CDMA, satellite and phone lines. A communications system may include more than one of the aforementioned technologies. The goal is to engineer the system to meet the present needs and accommodate future growth.
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Document ID:
DB7E3AC6
Economics Of Electronic Gas Measurement
Author(s): Shawn Kriger
Abstract/Introduction:
Electronic flow meters (EFM) or chart recorders? Old technology or new? These are two basic questions energy companies must answer when planning the short and long term goals for the measurement and control of their production, gathering or transmission systems. Many companies have already made the switch to electronics. They are using EFMs on every new field installation. They are also in the process of replacing charts that already exist in the field. Other companies have not made the switch. Chart recorders continue to be the main component of their gas measurement systems. Back in the early 1980s, electronic flow meter technology was still relatively new to the gas industry. Chart recorders were the standard and many companies were skeptical of the new electronics technology. Over the past twenty five years, electronic technology has consistently become better and more reliable. Battery and solar panel technology has improved. Microprocessors are faster and more reliable. Flow meters continue to gain additional functionality, which enable operators to perform total well site automation all from the same device. And most important, cost of electronic technology continues to drop.
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Document ID:
588EEEBF
Production Equipment Effects On Gas Measurement
Author(s): David Pulley
Abstract/Introduction:
American Gas Association states that measurement of natural gas by an orifice meter requires a single phase hydrocarbon through the metering area which allows an accurate measurement of differential pressure across the orifice plate, flowing temperature, and component analysis at a metering station. Some gas contracts state that the producer shall condition the gas for metering which would allow accurate measurement of gas flowing through the metering station. To meet the AGA and Contract requirements personnel need to have a knowledge and operational understanding of production equipment used to condition gas prior to the point of measurement. To achieve this condition field personnel should have an operational understanding of production equipment by which they can perform maintenance on and make adjustments to achieving an optimum flowing condition within the metering tube.
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Document ID:
F9ED35E9
Effects Of Cathodic Protection And Induced Signals On Pipeline Measurement
Author(s): Russell m. Gosselin
Abstract/Introduction:
In order to calculate flow rates and volumes in natural gas measurement, 4-20 maDC (milliamps direct current) signals are wired to an EGM (Electronic Gas Measurement) device. These signals become 1.0 to 5.0 Volts DC and are then scaled into engineering units to represent static pressure, differential pressure and temperature. Another signal source can be alternating current (AC) frequency signals (sine or square wave) prominently used in linear meter measurement. Both types of signals are used as variables in the AGA (American Gas Association) flow equations used in EGM and often for billing purposes.
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Document ID:
17C17D6D
Ethernet For Scada Systems
Author(s): Richard Rogers
Abstract/Introduction:
Since the advent of Ethernet more 20 years ago some control engineers have been hesitant to fully embrace the use of Ethernet communications with in their control systems. In this paper we will examine Ethernet from two different perspectives. The first is the 1980s perspective which is about the time that Ethernet made its debut in factory enviroments. The second perspective begins in the mid 1990s and continues right up through today.
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Document ID:
EF16440A
On-Line Computers For Custody Transfer
Author(s): Matthew A. Diese
Abstract/Introduction:
With the advent of Electronic Flow Measurement came a variety of calculation, auditing and calibration algorithms. Each manufacturer wrote software to meet either a producers requirement or their own proprietary algorithms. In the early phase of development, flow computer manufacturers tailored algorithms to meet their own hardware capabilities. These algorithms were then reviewed by users and modified to meet their own specific needs. These algorithms, while being effective, were by nature vastly different from one manufacturer to the next. These differences made it necessary to develop a standard for custody transfer meters so that regardless of the manufacturer, the measurement data will be consistent from one meter to the next. This standard became API Chapter 21 - Flow Measurement Using Electronic Metering Systems, Section 1 - Electronic Gas Measurement.
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Document ID:
2274AA79
Real-Time Electronic Gas Measurement
Author(s): King Poon
Abstract/Introduction:
With natural gas production in the United States peaked and demand rising, natural gas prices will go from the 1.50 / MCF that it has been in the past decade to 10.00 or more in the coming years. With this in mind, accurate gas measurement is paramount, and the delivery of this measurement data must be on time (i.e. accurate real-time data). Production, engineering, gas nomination, billing, and various administrative functions are just a few of the departments now requiring real-time information. Instead of charts, electronic flow computers are now used by the natural gas industry to automate the data collection and control process. Host computer systems periodically collect data from the flow computers and send control commands, gas analysis data, and configuration information to the flow computers as part of daily operations. The success of real-time measurement depends upon the coordination of many functions, including measurement and control, communications, data collection, archiving, post processing, reporting, and the sharing of this information. A breakdown in any of these functions affects the integrity of the entire system and prevents the data from being distributed to the end users in a cost efficient manner.
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Document ID:
DADE3C79
Spread Spectrum Systems For Efm And Scada
Author(s): Ben Hamilton
Abstract/Introduction:
The spread spectrum radio, especially the Frequency Hopping Spread Spectrum (FHSS), is becoming the preferred communications technology for the EFM and SCADA systems. The Federal Communications Commission (FCC) allocated spectrums in 3 bands for unlicensed use (CFR 47, part 15 - the FCC rules). Equipment manufacturers developed high quality, low cost equipment with robust features. The end users of this technology have accepted the innovations and are quickly deploying it. The demand for more information and the ability to remotely effect well site automation equipment will accelerate the use of this technology. Most Electronic Flow Meters (EFMs) are equipped with a local console communications port and one or more ports for remote communications. The most common method used to provide remote communications to a group of meters is with a FHSS radio network. The most common FHSS network is point-to-multi point. The network host is usually interfaced to the master at the hub of the network and the EFMs are connected to the remotes.
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Document ID:
07AAF7B5
Smart Transmitter Selection, Calibration And Installation
Author(s): Leon Black
Abstract/Introduction:
In 1985, while working on aeronautical transmitters at Honeywell Industries, Mr. Paul DuPuis described the definition of future transmitters. It has taken the industry 20 years plus to catch up with his forward thinking approach While researching the background for this paper, it became clearly evident that every manufacture in the industry has a different definition of SMART transmitter. Even the standards groups, IEEE, ANSI/ISA and others cannot agree on what constitutes a SMART transmitter. As defined a SMART transmitter is: Simple to use. The digital interface should relieve the system designer of the time consuming task of transducer research and design. Maintainable. Much of the transmitters functionality is governed by firmware, which allows it to be controlled tested and adjusted through a digital data link. Accurate. The user has only a single accuracy specification to understand. The specified accuracy of the transducer is sure to be fully realized when the transducer is integrated into the system. Reliable. The simplicity and stability of the digital mechanization insures it. Trainable. The microcomputer can be programmed to scale a limit output data in accordance with a field-inserted function.
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Document ID:
C08A8BD4
Testing, Maintenance, And Operation Of Electronic Flow Computers For The Gas Industry
Author(s): Stephen T. Stark
Abstract/Introduction:
Natural gas flow computers have been in use since the middle 1960s, becoming much more practical with the development of improved microprocessors in the 1980s and later advancements in more reliable transducers (e.g., temperature, pressure, differential pressure, etc.). In the earlier stages of development, gas flow computers calculated flow - and did very little else. Today in 2007, flow computers systems do much more than just measure flow, performing many SCADA-related tasks that are necessary in todays modern gas industry. Even so, and in the context of this paper, we will focus on the gas measurement related issues only.
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Document ID:
21809419
Transient Lightning Protection For Electronic Measurement Systems
Author(s): Dan Mccreery
Abstract/Introduction:
Energy supply is now a critical part of todays economy. This fact places increasing demands of reliability and availability on the control systems we use in this industry. Maximum availability and system reliability is mandated for both safety and maximum profitability. While considerable effort is expended in the evaluation of methods to improve processes, many engineers have yet to grasp the threat lightning and surges pose to modern control systems. As we have moved from analogue to digital control, from TTL to IC logic, our instrumentation and control equipment have become much more sensitive to voltage spikes. TTL components could sustain damage from an impulse with as little energy as 10J. Todays IC logic can be damaged from an impulse with as little as 1J of energy. It is very important that the protective systems we use today are designed to address todays modern and more sensitive equipment as well as the higher demands for improved uptime and reliability.
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Document ID:
29D95A22
Calibration Of Liquid Provers
Author(s): William R. Young
Abstract/Introduction:
A meter prover is used to calibrate custody transfer meters to establish a meter factor. The volume that passes through the meter is compared to the prover volume during the time taken for a sphere or piston to pass between two detector switches. The prover volume must be accurately determined by a calibration procedure known as the Water Draw method.
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Document ID:
501E1A5D
Design, Calibration, And Operation Of Volume Standards
Author(s): Sherry Sheckels
Abstract/Introduction:
Test measures are designed to deliver a known liquid volume when drained. Their primary use is to calibrate displacement and tank provers in the field by the waterdraw method.1, 2 Accurate test measure volume calibrations are critical to achieving low uncertainty calibrations with flow provers in the field. Test measures can either be invertible or bottom-drain type. Invertible test measures are usually less than 40 L (10 gal) while bottom-drain test measures are larger than 40 L (10 gal). Each year, approximately 100 test measures used for field calibrations are calibrated at the National Institute of Standards and Technology (NIST) to comply with API standards.3 NIST uses several calibration methods depending on the size of the test measure: 1) the gravimetric method, 2) the gravimetric transfer method, and 3) the volumetric method.4 NIST calibrations include a neck scale calibration at five levels spaced over the range of the neck scale. To ensure accurate customer calibrations and to maintain an ISO 17025 compliant quality system5 NIST regularly performs calibrations of the 60 kg and 600 kg balances used during the calibration and calibrates volume check standards.
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Document ID:
0A1E30CA
Effective Use Of Deadweight Tester
Author(s): Roger Thomas
Abstract/Introduction:
One of the most difficult problems facing the instrument engineer is the accurate calibration of pressure or differential pressure measuring instruments. The deadweight tester or gauge is the economic answer to many of these problems. This paper describes methods to select deadweight testers and gauges. Also included are procedures for using pneumatic and hydraulic deadweight testers.
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Document ID:
4F7E45E7
Flow Calibrating Ultrasonic Gas Meters
Author(s): Joel Clancy
Abstract/Introduction:
The primary method for custody transfer measurement has traditionally been orifice metering. While this method has been a good form of measurement, technology has driven the demand for a new, more effective form of fiscal measurement. Ultrasonic flowmeters have gained popularity in recent years and have become the standard for large volume custody transfer applications for a variety of reasons. Most users require flow calibrations to improve meter performance and overall measurement uncertainty. The latest revision of AGA Report No. 9, Measurement of Gas by Multipath Ultrasonic Meters, Second Addition Ref 1, now requires flow calibration for ultrasonic flow meters when being used for custody transfer applications. What considerations then, should be taken when choosing to flow calibrate an ultrasonic flowmeter? What are the benefits to the user? What should a user expect from a flow calibration? What kind of performance should the customer expect or accept from an ultrasonic meter? What are the diagnostic capabilities inherent in an ultrasonic meter? These areas, as well as others will be explored and considered.
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Document ID:
733AA9F8
Guide To Troubleshooting Problems With Liquid Meters And Provers
Author(s): Jerry Upton
Abstract/Introduction:
This paper deals with problems commonly experienced with meters and provers. It is general in nature and cannot cover every problem with either meters for provers. We will confine our discussion to displacement and turbine meters and pipe and tank provers. We will also discuss problems experienced with proving meters with different types of proving equipment.
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Document ID:
6983B48A
In-Situ On-Site() Gas Meter Proving
Author(s): Edgar B. Bowles, Jr.
Abstract/Introduction:
Natural gas flow rate measurement errors at field meter stations can result from the installation configuration, the calibration of the meter at conditions other than the actual operating conditions, or the degradation of meter performance over time. The best method for eliminating these or other sources of error is with in-situ (on-site) calibration of the meter. That is, the measurement accuracy of the field meter station should be verified under actual operating conditions by comparing to a master meter or prover. Field provers have been developed for operation at high line pressures and flow rates. For purposes of this discussion, a high gas flow rate is any flow greater than 3,000 actual cubic feet per hour or (85 m3/h) at pressures to 1,440 psig (10 MPa). A field meter prover may be either a primary flow standard or a secondary flow standard. A primary flow standard is any measurement device that determines the gas flow rate from the fundamental physical measurements of mass (M), length (L), temperature (T), and time (t). Measurement devices based on other techniques or methods are categorized as secondary flow standards. For highest accuracy, a secondary flow standard (sometimes also called a transfer standard) must be calibrated using a primary flow standard at operating conditions.
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Document ID:
2F5F46FE
Lact Unit Proving - The Role Of The Witness
Author(s): Art Casias, Terry Ridley
Abstract/Introduction:
Witness, as defined by the New Websters Dictionary, 1.n, a person who has observed a certain event, the unwilling witness of a quarrel a person who testifies to this observation, esp. in a court of law, and esp. under oath a person who testifies to the genuineness of a signature on a document by signing his own name to the document an authentication of a fact, testimony public affirmation of the truths of a religious faith something taken as evidence, to bear witness to declare, on the strength of personal observation, that something is true to give as evidence, to bear witness, knowledge, testimony. The role of the witness, in the proving of a LACT unit, requires you to understand the operations of both the LACT and ACT units and the device used in proving their accuracy.
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Document ID:
A6C7F469
Liquid Flow Provers
Author(s): Darin L. Johnson
Abstract/Introduction:
The petroleum industry has used conventional pipe provers for on line calibration of liquid flow meters for over 40 years. With the widespread use of turbine meters, positive displacement meters, and liquid ultrasonic meters for custody transfer, accurate measurement is more dependent on frequent proving. Thus the industry will continue to demand advanced provers and proving techniques. The author will discuss the aforementioned subject with regard to both bidirectional and unidirectional pipe provers. In the last several years, a number of innovations have come to the forefront that enhance the reliability of pipe provers, reduce their size, make them more accurate, and increase their value to the end users. A description of the operational principles of pipe provers and the enhancements that are now available in terms of prover mechanical configuration and electronic instrumentation will be described in detail. In addition, information will be provided concerning reliability, the design and use of sophisticated computer control systems for automated proving, and the integration of pipe provers into metering systems.
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Document ID:
75D44C10
Liquid Meter Proving Techniques
Author(s): Peter P. Jakubenas
Abstract/Introduction:
This paper will cover the techniques that are important for proving various types of liquid meters in accordance with API Chapter 4.8. As the price of crude oil and refined products increases the need for proving and proper equipment and techniques for proving becomes more important and the justification for investment in proving equipment and maintenance of the equipment becomes easier. Mis-measurement of even 0.05% on a stream flowing at 2,000 BPH or 48,000 BPD of 90 crude oil costs 790,000 per year. Under-registration deprives the company of entitled revenue, over registration raises the issue of customer complaints, retroactive rebates, and potential lawsuits.
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Document ID:
572A391B
Operation & Problems Associated With Prover Detector Switches
Author(s): Warren A. Parr, Jr.
Abstract/Introduction:
In many parts of the petroleum industry, sphere provers are used to dynamically calibrate volumetric meters. In order to accomplish this, sphere provers are required to be accurate and repeatable. This accuracy and repeatability is largely dependent on performance of the prover sphere detector. Any operational or design problems associated with the prover detector will affect the provers performance. This paper will review critical parts of a prover sphere detector that must be checked in order to obtain accuracy reliability and repeatability. The areas that will be covered are: Prover detector accuracy. Prover detector mechanical repeatability. Prover detector electrical repeatability. Prover detector performance due to prover sphere contact length. System accuracy and repeatability.
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Document ID:
C5E32C7D
Operational Experience With Small Volume Provers
Author(s): Steve Whitman
Abstract/Introduction:
Introduced decades ago, Small Volume Provers (SVPs) are now common technology. There are numerous publications providing empirical data and outlining the technical operation of this equipment. The following document will focus on the authors experience, addressing common concerns and questions regarding SVPs.
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Document ID:
934CE505
Proving Coriolis Meters
Author(s): Marsha Yon
Abstract/Introduction:
Coriolis meters are in use throughout the hydrocarbon industry for the measurement of fluids including crude oil, products such as fuel oil, gasoline, and diesel, and light hydrocarbons such as natural gas liquids, propane, etc. When used for custody transfer, it is most often required by contract between the buyer and seller that the meter be proven in the field on the fluid that is being measured and at the conditions under which it will be operating. This paper will utilize the American Petroleum Institutes Manual of Petroleum Measurement Standards (MPMS) as the reference for industry practices for field proving methods and calculations. Coriolis meters can measure volume, mass and density. If the meter is used to measure volume and the pulse output represents volume, the meter should be proven as a volume meter. MPMS Chapter 4, Proving Systems, contains information specific to volumetric proving. If the meter is used to measure mass and the pulse output represents mass, the meter should be proven as a mass meter. Currently Chapter 4 does not contain information relative to proving on a mass basis however MPMS Chapter 5.6, Measurement of Liquid Hydrocarbons by Coriolis Meter, does provide guidelines for mass proving. If the density output is used for custody transfer flow calculations, the density measurement can be proven using MPMS Chapter 14.6, Continuous Density Measurement and a pycnometer or using MPMS Chapter 9, Density Determination and a hydrometer. The temperature output of a Coriolis meter is obtained from an internal RTD which is not inserted into the fluid and thus does not meet MPMS Chapter 7, Temperature Determination requirements and should not be used for custody transfer calculations. This paper will attempt to combine information from these standards with field experience to provide an overview of what to expect when proving a Coriolis meter and what to look for if the proving results are not satisfactory.
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Document ID:
137566B2
Theory And Application Of Pulse Interpolation To Prover Systems
Author(s): Galen Cotton
Abstract/Introduction:
Here we take an in-depth look at the use of Pulse Interpolation as it applies to reduced volume provers (captured piston provers in current API parlance), or Small Volume Provers (SVP) and the implicit in reliability of the technique where the fundamental conditions implicit in its use prevail.
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Document ID:
AA27FF85
VERIFICATION/CERTIFICATION Of Devices Used In Liquid Measurement
Author(s): Anne Walker Brackett
Abstract/Introduction:
In the past the standards from the American Petroleum Institute and the American Society for Testing and Standards provided specifications for instruments and equipment. Simple compliance with these standards is not enough. Therefore, a system of verification and/or certification of equipment used in measurement of liquids are being instituted. These requirements are being written into the standards as they come up for review. An excellent example of such a standard is Chapter 3.1.A. Standard Practice for the Manual Gauging of Petroleum and Petroleum Products (December, 1994.) This standard is currently being revised.) of the APIs Manual of Petroleum Measurement. 3.1.A. calls for field verification of working tapes against against a National Institute of Standards and Technology traceable master tape when it is new and every year thereafter. This is an example of requirements to insure the instrument and the equipment meets the specifications of each standard. The most important things to understand before going into each item are the definitions of traceability, verification, and certification.
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Document ID:
283E42EF
Witnessing Orifice Meter Calibrations And Field Testing
Author(s): Chann Underwood
Abstract/Introduction:
We are far removed from the good old days of plus or minus 2% or when the most important thing to be considered in witnessing a meter test was where we were eating and whose turn it was to pay. With the cost of drilling, development and transportation steadily increasing, the producer, pipeline operator and distribution system owner are more conscious and concerned about the accuracy in which their product is bought and sold than ever before. The volatility of the market and the many different factors affecting the quality and quantity of the gas has made the custody transfer point critical in marketing this commodity on a day to day basis. In most cases a contract will be agreed upon by both parties detailing the particulars on how this transfer of natural gas is to be completed. The purpose of this paper is to outline the responsibilities of a companys representative and discuss some good practices for witnessing the transfer of this product.
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Document ID:
F06F82C2
Improving Flow Measurement Through Improved Calibration And Data Handling Procedures
Author(s): Duane A. Harris
Abstract/Introduction:
The knowledge base from a field measurement technician to a back office volume analyst is extremely demanding. Every field technician is tested in both knowledge and skills on a daily basis for: electronic controls to pneumatic controls communication system support multiple disciplines support of measurement equipment procedures that must be followed regulatory requirements governing the facilities ongoing training of field personnel These factors and many more create a tremendous and constant challenge for every organization.
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Document ID:
3A6AAC43
Auditing Gas Laboritories
Author(s): Joe Landes
Abstract/Introduction:
The data produced by Gas Chromatograph (GC) laboratories is used for many purposes, including product specification, accounting, safety and environmental compliance issues. The accuracy of this data has direct impact on all of these areas. Auditing laboratories responsible for producing this data is prudent business practice. The audit will provide a means of process improvement, through proper identification of deficiencies and a precise plan for corrective action. The level of confidence in analytical results will increase when the appropriate corrective actions are implemented. The amount of financial and legal exposure can be reduced from a properly executed audit program.
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Document ID:
9C90A127
Btu Values From A Gas Chromatograph
Author(s): David Harms, Cris Angelos
Abstract/Introduction:
Gas Chromatography provides the compositional data required to calculate a BTU heating value of Natural Gas. Various types of BTU values can be derived based on physical state assumptions of the gas. A generic, stepwise procedure is presented to show how a BTU value is determined from Gas Chromatography data.
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Document ID:
703B2827
Btu Determination Of Natural Gas Using A Portable Chromatograph
Author(s): Burt Reed
Abstract/Introduction:
The analysis of natural gas by using a gas chromatograph has become the one of the most important components in gas measurement in todays energy industry.
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Document ID:
2C55C4A8
Chromatograph Maintenance And Troubleshooting
Author(s): Lloyd W. Winn
Abstract/Introduction:
Measurement of natural gas requires a variety of instrumentation, only one of which is the gas chromatograph. The sale of natural gas is performed on the basis of the heating value per unit volume of the gas (MMBtu). For this reason the need for proper sampling and/or portable on-line instruments is needed. There are five major sources of problems in gas chromatography: 1. the operator, 2. the sample, 3. the column, 4. the equipment or electronics, and 5. the gas flow system. Eliminate these sources in a systemic manner to isolate the cause of a problem. A few basic rules make troubleshooting faster and easier. Most important are maintaining close observation of operating parameters and a good record keeping system (temperatures, flow rates, and column type are a few.) Also of primary importance are reference chromatograms and reference standards containing known concentrations of the components in your samples, with no extraneous components. Many hours can be wasted hunting problems within an instrument or column, when the problem is the sample being analyzed. If your chromatographic system separates the reference standard well and reproducibly, the problem most likely is related to the sample.
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Document ID:
0AE95E0B
Chromatographic Analysis Of Natural Gas Liquids
Author(s): John Dempster
Abstract/Introduction:
The purpose of this paper is to introduce people who have little or no knowledge of chromatographic methods to the techniques employed for establishing chemical composition, and the resultant calculation of heat energy in natural gas transported by pipeline. The method is for semi continuous on-line chromatographic analysis. This method is essential to establishing the value of the gas and so its sale price. The installations at the pipeline must be low maintenance, accurate and reliable. The analysers discussed have been used since around1978 and have developed according to needs. Process GCs (Gas Chromatographs) in refining and chemicals have mostly needed to be housed in shelters to control ambient temperatures and offer protection from the elements. But due to the remote location of pipeline installations analysers were needed that were more robust with low utility consumption and a wide ambient temperature operating range.
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Document ID:
2CC3ABB3
Crude Quality - What Is Involved And Why Is Quality Important
Author(s): D. Pat Morgan
Abstract/Introduction:
Crude Quality - What is Involved and why is Quality Important is a major issue in the petroleum industry today. A Crude Quality Oversight program is designed to monitor the ongoing quality of a crude supply by measuring certain key properties, which directly correlate to quality, value and performance. There are many benefits to this type of monitoring program. It: Keeps suppliers honest Allows ongoing valuation of individual crude streams, used in trading crudes for refinery supply Supports refinery operations & optimization efforts Identifies possible contamination sources Supports regulatory compliance efforts
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Document ID:
5A8C3328
Determination Of Hydrogen Sulfide And Total Sulfur In Natural Gas
Author(s): David Haydt
Abstract/Introduction:
Hydrogen sulfide and other sulfur bearing compounds exist naturally in many natural gas fields throughout the world. It is generally necessary to remove these sulfur bearing compounds from the gas in order to preserve public safety, reduce corrosion in pipelines, meet contractual agreements and to control odor in the gas. Thus the determination of hydrogen sulfide and total sulfur in natural gas is critical to the natural gas industry.
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Document ID:
BC3D6585
Determination Of Water Vapor Content In Natural Gas
Author(s): Murray Fraser, Charlie Cook
Abstract/Introduction:
Gas Quality Analysis encompasses a variety of technologies and sample handling challenges for field analyzers and operations personnel. This paper will focus on moisture analysis in Natural Gas using new laser-based technologies known as Tunable Diode Lasers or TDL. In addition the paper will discuss conventional technologies for moisture analysis. Additional topics will include best practices for sample conditioning in -40C operating environments and an in-depth review of actual field conditions where disputed moisture measurements were a concern at an inter-company custody transfer point in Alberta. Observations, recommendations and validation procedures will be presented that may be useful anytime the dew point of natural gas is in dispute.
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Document ID:
CD6D651D
Determination Of Hydrocarbon Dew Point In Natural Gas
Author(s): Andy Benton
Abstract/Introduction:
This paper considers the requirements for control of hydrocarbon dew point in natural gas and how measurement of this important gas quality parameter can be achieved. A summary of the commercially available on-line instrumentation is provided covering: Manual, visual technique with cooled mirror dewpointmeter Equation of state calculation from extended composition analysis by gas chromatograph Automatic, optical condensation dewpointmeter
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Document ID:
1EFDD1F2
Hydrocarbon Dew Point Effects On Gas Flow Measurement
Author(s): Noelle Dildine
Abstract/Introduction:
Since the implementation in the last ten years of improved measurement equipment such as C9+ chromatographs and electronic chilled mirror devices, the hydrocarbon measurement industry has been debating the procedures for hydrocarbon dew point measurement. Which type of measurement is most accurate? What measurement most accurately predicts liquid dropout? What should be used as the standard? The debate is complicated by the needs of different types of companies within the industry. Which measurement technique is most relevant for a specific companys needs? Can there be an industry-wide standard for measurement of hydrocarbon dew point? These are questions that can not be answered in one paper and may not be answered without several years of additional research and debate. However, it is still important to understand how to obtain the most relevant data with the different types of measurement techniques available today. Why do samples taken at the same time from the same location give different measurement values? What can be done to obtain a more accurate reading? How can hydrocarbon dew point and phase behavior affect other important measurements? An understanding of hydrocarbon dew point and phase behavior can help engineers, technicians, and others perform tests more accurately and interpret results more effectively.
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Document ID:
BA56BAAE
D.O.T. Requirements For The Transportation Of Sample Cylinders
Author(s): David J. Fish
Abstract/Introduction:
The United States Department of Transportation (D.O.T.) is a department of the U.S. Federal Government which oversees all issues regarding transportation within the United States of America and U.S. Territories. Its influence around the world is great and widely respected, but its jurisdiction and power of enforcement is limited to the USA and its territories. As regards this paper, we will discuss the D.O.T. and its involvement surrounding sample cylinders for the hydrocarbon industry and the rules regarding the movement of these cylinders from point to point in the United States. The most important statement to be made is that the D.O.T. and Code of Federal Regulations, Title 49 (CFR-49) is the definitive and final authority on all issues regarding the handling and transportation of sample cylinders. Much has been written and quoted over the years and many regulations have changed over the years. It is the sole responsibility of each company involved with sample cylinders, to have a copy of CFR-49 and to be responsible for clarification of any issues they have, by researching CFR-49 and consulting with D.O.T. representatives. They have the final word on any questions. D.O.T. is the enforcement agency regarding sample cylinder transportation. The author of this paper and the company he represents do not present themselves as authorities on this matter for you or your company. This paper is presented for the sole purpose of providing limited information and to encourage you and your company to become better informed for your specific needs and operations.
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Document ID:
EE08DED3
Energy Measurement Using Flow Computers And Chromatography
Author(s): Burt Reed
Abstract/Introduction:
The means and methods of transfer of quantities of natural gas between buyers and sellers have been changing for many years. When coal gasification was used to fuel the streetlights in Atlanta, Ga. There was no reason to even measure the commodity. The municipality generated the gas, transported it, and burned it. When Frank Phillips started purchasing gas rights back in the 1930s, every one thought he was more than odd. Natural Gas was considered at that time a messy by-product of oil production that had to be disposed of. Even during the 1960s natural gas was still being flared at the wellhead in Oklahoma. During the 1940s, it was said that one could drive from Kilgore, Texas to Tyler, Texas at night without turning on the head light on your car due to all the gas flares. In this economic environment, measurement was not an issue if you could sell the gas at all it was considered a business coup. Even then, a good price was 2 cents an MCF. But when Henry Ford was building the Model T, gasoline was a refinery waste product that the heating oil manufacturers were glad to get rid of. Not so now. So, as with other cheap forms of energy, both the use and the infrastructure for natural gas grew. Natural Gas prices were tied to oil prices very tightly until the 1990s. If oil went up, so did Natural Gas. When it went down, down came the gas prices. Even though many electric power plants had been built with the capability to burn multiple sources of energy, like coal, oil and Natural Gas, the increasing pressure to clean up the environment, caused Natural Gas to become the preferred energy source. This factor plus the maturing pipeline infrastructure have now led to Natural Gas becoming its own independent commodity.
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Document ID:
2B567EB3
Field And Laboratory Testing Of Sediment And Water In Crude Oil
Author(s): Del J. Major
Abstract/Introduction:
In this paper we will discuss the different methods of determining the quantity of sediment and water content in crude oil. We will also discuss some of the problems associated with the field-testing methods and attempt to better understand how those problems affect your Companys bottom line. Custody transfer of crude oil takes place by determining the quantity and quality of the product exchanging ownership. Precise and accurate measurement with minimal bias errors is essential in custody transfer applications. Although sediment and water determination is often thought of as a quality indicator, it actually affects the quantity since its quantity is deducted from the final volume transferred. The allowable amount of sediment and water that can be accepted is based on tariff restrictions that are spelled out by the transporting Company or system.
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Document ID:
3735C64D
Heat Quantity Calculation Relating To Water Vapor In Natural Gas
Author(s): Edgar B. Bowles, Jr., Darin L. George
Abstract/Introduction:
Natural gas oftentimes contains some amount of water, in either vapor or liquid form. The solubility of water in natural gas flowing through a pipeline is a function of the pressure and temperature of the flow stream. The amount of water affects the heating (calorific) value per unit volume of natural gas. The more water present in the gas, the less valuable it is as a fuel, since the water does not burn. This water, in vapor form, is sometimes referred to as spectator water and it displaces the hydrocarbon components in a natural gas mixture. The net effect is a reduction in heating value and monetary value per unit volume of gas. The amount of water vapor contained in a natural gas mixture is customarily expressed in terms of the mass of water per unit volume of gas for example, pounds mass of water per million standard cubic feet of natural gas (lbm/MMSCF). If water is present in natural gas that is to be transported, a decision must be made as to whether or not the water should be removed. There is obviously a cost associated with removing and disposing of water extracted from natural gas. Even if the water in left in the gas to avoid the removal costs, there is still a cost, because the water has mass, which requires energy (or compression horsepower) to transport. Another important consideration is that water is one of the constituents that can cause corrosion in the steel pipes used to transport natural gas. Repairing or replacing corroded pipelines can be a significant expense. In addition, corroded pipelines may degrade operational safety and system reliability. There are also issues associated with how water adversely affects the combustion process when natural gas is used as a fuel. As one can see, there are a number of considerations to take into account when deciding how much water to remove from a natural gas flow stream. Gas transportation and delivery contracts and tariffs usually limit the amount of water allowed in transmission- and distribution-grade natural gas streams as one way to help control the amount of water introduced into the natural gas pipeline grid in the United States. This paper explains how to account for water vapor when calculating the heating (or calorific) value of natural gas.
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Document ID:
5801D050
Measurement Of Liquefied Petroleum Gas
Author(s): Fred G. Van Orsdol
Abstract/Introduction:
LPG products include propane, iso-butane and normal butane. These products can be stored or transported as liquids at moderate pressures and ambient temperatures. Transporting LPGs in the liquid phase is much more efficient than transporting them in the vapor phase, since so much more mass can be contained in the same space. One gallon of liquid propane, for example, will produce about 36 cubic feet (269 gallons) of propane vapor at atmospheric pressure and 60F. LPGs are produced by refineries separating and fractionating the light ends from crude oil or by natural gas processing plants that remove and fractionate the heavier components (propane plus) in the natural gas stream. Ethane is not generally considered to be an LPG, even though gas plants extract it from natural gas. It requires high pressure or very low temperatures to maintain ethane in the liquid phase. Ethane products typically serve as feedstock for chemical plants.
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Document ID:
BF6ED3AC
Interface Detection In Liquid Pipelines
Author(s): Steve Stewart
Abstract/Introduction:
Since the earliest days of pipeline operations, refined products pipelines have been tasked with the challenge of developing interface detection methods to help identify, isolate, and store multiple fuel products as they flow through pipeline and fuel distribution networks. Although interface detection has been a standard procedure for many years in the pipeline industry, recent developments of specialty fuels such as reformulated gasolines, low sulfur fuels, and unique-blend fuels have created a renewed emphasis on interface detection. In order to meet this challenge, a need for improved interface-detecting technology, and improved interface-detecting procedures have been developed to help pipeline operators track and isolate products as they flow through the pipeline system.
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Document ID:
2CA5D682
Sampling And Conditioning Of Natural Gas Containing Entrained Liquids
Author(s): Donald P. Mayeaux
Abstract/Introduction:
The monetary value of natural gas is based on its energy content and volume. The energy content and physical constants utilized in determining its volume are computed from analysis. Therefore correct assessment of the value of natural gas is dependent to a large extent on overall analytical accuracy. The largest source of analytical error in natural gas is distortion of the composition during sampling. Sampling clean, dry natural gas, which is well above its Hydrocarbon Dew Point (HCDP) temperature is a relatively simple task. However, sampling natural gas that is at, near, or below its HCDP temperature is challenging. For these reasons, much attention is being focused on proper methods for sampling natural gas which have a high HCDP temperature. This presentation will address problems associated with sampling natural gas which is at, near, or below its HCDP temperature. Various approaches for solving these problems will also be discussed.
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Document ID:
180BF687
Techniques Of Natural Gas Composite Sampling
Author(s): Greg Lewis
Abstract/Introduction:
In todays competitive market, a producer of natural gas must strive to maximize their market value and achieve the highest return on invested income. In order to accomplish this goal they must ensure they are receiving full value for the natural gas products that they produce. In addition to the producer, it is extremely important for the other stakeholders, whether they be government, gathering system operator, processor, or transporter to do their due diligence to ensure they are also receiving or properly accounting for the true and full value of the natural gas products that pass through their systems. This is because royalty rates, transportation levies and processing fees are based on the value of the natural gas being commercially bought and sold, processed or transported. Receiving less than full value for the product produced comes directly off the bottom line of the company. Attention must be brought to the impact that accurate sampling, analysis, measurement, and allocation has in determining the true value of this energy resource to the government, the producer, the processor, and the transporter. As an example, let us consider the job of a production accountant. The job of a production accountant is to accurately allocate the produced natural gas product back to its sources or owners. This is complicated by the fact that the wells may be owned by different companies and may flow into a common gathering system. There may be lean wells as well as rich wells, sweet wells, or sour wells. The gathering system may then transport the combined flows to a common gas plant for processing. It becomes clear that the challenge for the production accountant is to ensure that every stakeholder will be compensated correctly based on the volume and quality of the gas that they produced.
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Document ID:
FE5B16E0
Techinques Of Gas Spot Sampling
Author(s): Stephen Palmitier
Abstract/Introduction:
The requirement for consistent, repeatable, representative gas samples is driven by both economics and by operations. The monetary value of the gas is principally determined by its energy content as expressed in British Thermal Units (BTU). The BTU value of the flow of natural gas needs to be established at various transfer points so that all parties to the transactions are treated equitably. The BTU value of the gas needs to be determined where it enters a plant so that operations may be balanced. Accurate samples are also important in maintaining the integrity of the pipeline. There are three basic methods for sampling gas. One method is to periodically take a spot sample. The spot sample is a single sample that is taken periodically and analyzed to determine BTU value. Another method is the use of an online analyzer. Small samples are taken from the flow and analyzed real-time at the collection point. The third method used is to collect composite samples. The composite sample is a physical mix of small individual sample units taken over time that are analyzed as a group. The composition of the sample can be corrupted by poor technique (including the equipment used). Regardless of the method used, proper sampling is fundamental in determining the correct composition of the gas. Fair trade, plant balance, and pipeline integrity demand it. This paper will focus on techniques of spot sampling.
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Document ID:
E17A193C
Determination Of Hydrocarbon Dew Point Using A Gas Chromatograph Determining Hydrocarbon Dew Point Per Gas Chromatographic Analysis And Equations Of State
Author(s): Shane Hale
Abstract/Introduction:
The determination of the Hydrocarbon Dew Point (HCDP) for Natural Gas has recently become a critical issue for the Natural Gas industry due to the rapid expansion of interconnecting pipelines and the rise of the Liquefied Natural Gas (LNG) as an international source of Natural Gas. Where previously the Natural Gas in a pipeline would come from a small number of known producers, the Natural Gas flowing through the pipeline today could have come from many varied sources including traditional Gas Plant producers (De-hydration, CO2 and/or N2 control and removal of Condensates), Coal Bed Methane producers (98% Methane), low cost producers (De- Hydration only) or global exporters of LNG. Economic factors have also played a role in the changing quality of the gas. As the Natural Gas prices have increased, producers who have previously stripped the heavier components out of the gas to produce condensates have realized a greater return by leaving the higher energy value heavy Components in the export Natural Gas.
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Document ID:
3CF0AACD
Fundamentals Of Sampling Natural Gas For Btu Determination
Author(s): Donald P. Mayeaux
Abstract/Introduction:
This paper discusses the fundamentals of extracting, conditioning, and transporting natural gas samples for on line BTU analysis.
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Document ID:
CFFA513C
Moisture Measurement Using Laser Spectroscopy
Author(s): Samuel C. Miller
Abstract/Introduction:
The need for reliable moisture measurement is essential to natural gas companies because of the corrosive nature of the moisture in combination with compounds such as carbon dioxide and hydrogen sulfide. Natural gas processors and pipeline operators must measure moisture and other contaminants to protect equipment and to conform to customer specifications. Since TDL analyzers provide very fast and reliable measurements, they are commonly used in the control loops of purification, separation, and liquefaction processes to optimize efficiency and costs. This paper will review the background of TDL spectroscopy, the theory of operation, and the measurement performance that can be achieved. It will also cover installation issues that are important to getting good measurements and it presents data comparing TDL measurements to a Bureau of Mines type chilled mirror. TDL spectroscopy can provide accurate measurements of moisture as well as carbon dioxide and hydrogen sulfide in natural gas much faster and more reliably than other methods.
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Document ID:
3296AEED
Reducing Measurement Uncertainty In Process Gas Quality Measurements
Author(s): Darin L. George
Abstract/Introduction:
The general term gas quality is used to refer to many different measures of the content of a natural gas stream. Common measures of gas quality include heating value, water vapor content, hydrogen sulfide or total sulfur content, levels of inert gases such as CO2, and hydrocarbon and water vapor dew points. These values determine how the gas stream must be handled, whether it can be used efficiently by customers, and whether the potential exists for damage to end-user equipment or pipelines that carry the gas stream. The presence of water and hydrogen sulfide in a gas stream, for instance, can create sulfuric acid and pit the walls of a pipeline. Shifts in heating value and specific gravity of the gas can lead to poor furnace performance, or require adjustments of gas-fired industrial equipment. High levels of non-hydrocarbon gases will reduce the heating value and make transportation of the gas less economically efficient. To determine whether natural gas meets gas quality standards in their transportation tariffs, producers and transmission companies must accurately measure all contents of the stream that affect gas quality. Accurate gas quality data will also be crucial to the effective introduction of liquefied natural gas (LNG) and marginal gas supplies into the natural gas transmission network in the near future. Accurate gas quality measurements depend not only on the instruments used to make measurements, but on the methods and equipment used to carry samples to the instruments.
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Document ID:
B4E8A16A
CO2 Determination Of Natural Gas Streams
Author(s): Charlie Cook
Abstract/Introduction:
Carbon Dioxide is measured in Natural Gas for two reasons. First and most often it is measured for energy determination (BTU/CV) by gas chromatography. And the second reason CO2 is determined is for pipeline integrity. The measured data is transmitted in various ways for records keeping as well as operational input. CO2 measurement for energy determination is typically made by gas chromatography. Gas Chromatography is employed in two ways - on line gas chromatography which is used primarily for custody measurement in larger meter stations or by laboratory measurement of composite samplers. CO2 determination is useful or even required as upstream and downstream companies attempt to manage their operations more effectively. Priorities vary among these companies as well as budgets. Therefore each method may be justified by specific operation needs to be discussed later.
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Document ID:
1C79C3B2
Flare Measurement Practices
Author(s): Curtis Gulaga
Abstract/Introduction:
There has been an increased awareness by oil and gas companies in North America toward emissions monitoring and reduction for both environmental and economical reasons. For years, several countries worldwide have had stringent regulations in place. Regulations were implemented in 1993 relating to the measurement of fuel and flare gas for calculation of CO2 tax in the petroleum activities on the Norwegian continental shelf. Inevitably, oil companies operating in the region had to comply with these regulations. With new government legislation, producers, refineries and chemical companies have been looking for a cost effective solution to reduce emissions and to provide tighter control for both leak detection and mass balance. To tolerate the extreme process conditions often found in a flare line, yet provide accurate measurement to comply with international regulators such as the Energy Resources Conservation Board in Canada, the European Union, or the Texas Commission of Environment Quality, the technology of choice is important. Several metering technologies have been tried and tested, and continue to have little success today. To understand why the results have been dismal, one needs to fully understand the application challenges and the limitations of the various flow-metering technologies used.
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Document ID:
D1EBEC59
Causes And Cures Of Regulator Instability
Author(s): William H. Earney
Abstract/Introduction:
This paper will address the gas pressure reducing regulator installation and the issue of erratic control of the downstream pressure. A gas pressure reducing regulators job is to manipulate flow in order to control pressure. When the downstream pressure is not properly controlled, the term unstable control is applied. Figure 1 is a list of other terms used for various forms of downstream pressure instability. This paper will not address the mathematical methods of describing the automatic control system of the pressure reducing station, but will deal with more of the components and their effect on the system stability.
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Document ID:
6B2456CF
Controlling Surges In Liquid Pipelines
Author(s): Ron Kennedy
Abstract/Introduction:
Numerous technical papers have been written on unsteady state surge flow or water hammer. This paper, unlike many of its predecessors, will present a view adapted to the engineer/technician who, for one reason or another, only needs a basic understanding of why surge occurs and how to control it. This paper will discuss the following topics: 1. History 2. Definitions/terminology 3. Why surge occurs 4. Problems from inadequate surge protection 5. Controlling Surges
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Document ID:
0FF64401
Fundamentals Of Pressure Regulators
Author(s): Thomas Weyer
Abstract/Introduction:
Gas pressure regulators have become very familiar items over the years, and nearly everyone has grown accustomed to seeing them in factories, public buildings, by the roadside, and even in their own homes. As is frequently the case with many such familiar items, we all have a tendency to take them for granted. It is only when a problem develops or when we are selecting a regulator for a new application that we need to look more deeply into the fundamental of the regulators operation.
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Document ID:
A6213F74
Overpressure Protection Methods
Author(s): Craig Lam
Abstract/Introduction:
The natural gas industry utilizes many different types of pressure regulation equipment to control the flow of gas as it flows from systems with higher pressure ratings to systems with lower pressure ratings. In the event that the pressure control equipment fails, some form of over pressure protection is required to prevent the system with the lower pressure rating or lower MAOP (Maximum Allowable Operating Pressure) from being over pressured. There are three primary methods of over pressure protection in the natural gas industry, which are: shut-off, relief, and monitor regulation. This paper will summarize the regulations that apply to over pressure protection in the natural gas industry and examine each of the three methods, with their advantages and their disadvantages.
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Document ID:
E672BAE3
Prevention Of Freezing In Measurement And Regulating Stations
Author(s): David J. Fish
Abstract/Introduction:
The failure to supply natural gas upon demand can cause irreparable damage to a companys corporate image in the 21st Century. Consistent and continuous pipeline operations are key and critical factors in todays natural gas pipeline industry. The competitive nature of the business, together with the strict rules and regulations of natural gas supply, mandate that companies stay on top of all operational parameters that could cause interruption or complete shut-down of the natural gas supply to customers. Identifying what may ultimately cause problems is a first step to controlling and eliminating those problems for the supplier. The natural phenomenon of freezing is a common occurrence in the operation of a natural gas pipeline system. Whether the gas is produced gas from a crude oil well, or natural gas from a gas well, the possibility for hydrates and the resultant problems, is real. Freezing is a potential and serious problem starting at the production wellhead through the last point in the customer delivery system. The occurrence of freezing is continuously reduced each step of the way, but care must be taken at each and every step to assure smooth operational conditions and satisfied consumers at the end of the line.
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Document ID:
DF00A79C
Selection, Sizing, And Operation Of Control Valves For Gases And Liquids
Author(s): Matt Lyndoe
Abstract/Introduction:
Proper control valve sizing and selection in todays industrial world is essential to operating at a cost-effective and highly efficient level. A properly selected and utilized control valve will not only last longer than a control valve that is improperly sized, but will also provide quantifiable savings in the form of reduced maintenance costs, reduced process variability, and increased process availability. An undersized valve will not pass the required flow, while a valve that is oversized will be more costly and can cause instability throughout the entire control loop. In order to properly size a control valve, one must know the process conditions that a given valve will see in service. Proper valve selection is not based on the size of the pipeline, but more importantly, the process conditions and a combination of theory and experimentation used to interpret these conditions.
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Document ID:
F62DCF27
Turbulence And Its Effect In Measurement And Regulator Stations
Author(s): Tracy D. Peebles
Abstract/Introduction:
The effect of turbulence on measurement and regulator stations can cause erroneous measurement as well as pipe fatigue, noise levels that are not healthy for the human ear, and a host of other undesirable elements.
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Document ID:
5C0E1081
Allocation Measurement
Author(s): Jeffrey L. Savidge
Abstract/Introduction:
Allocation is the process of assigning the proper portions of aggregated product flows back to individual source streams, owners, leases or measurement point. The assignment process is a standard method that is agreed upon and used by contracting parties. It is designed and intended to be fair, cost efficient and practical. By providing an efficient product sales transaction mechanism, allocation measurement helps to reduce capital and operating costs without jeopardizing the principal goal of fair treatment among parties. Reducing fluid measurement costs facilitates the development of marginal fields. Allocation measurement can fall under federal or regulatory guidelines. Individual agreements must meet or exceed those guidelines. API MPMS Chapter 20.1 is the industrys allocation measurement standard. Without it volumes of technical measurement documents would be required to accompany commercial contracts. The first edition of API 20.1 was prepared in 1993 and recently reaffirmed in 2006. Its scope is to provide a set of design and operating guidelines for implementing liquid and gas allocation measurement systems. As such, it provides recommendations for metering, static measurement, sampling, proving, calibrating, and calculation procedures. Due to the breadth of the measurement topics covered under allocation measurement, API Chapter 20.1 focuses on identifying procedures, providing practical and technical guidance in implementing allocation metering systems, and acts, in part, as a master guide to other important measurement guidelines.
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Document ID:
37D6E1E0
Orifice Meter Primary Elements Standards
Author(s): Jerry Blankenship
Abstract/Introduction:
The April 2000 revision to the API 14.3 part 2 Standard includes the results of considerable test work over the past few years. Numerous changes are noted, some of which will have major effects on users of orifice measurement. The most significant impact will be in the upstream length and flow conditioner areas. This paper will discuss most of the changes and go into some detail on the more important ones. Items not mentioned essentially remain as stated in the previous issue of the Standard.
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Document ID:
064275E8
Auditing Electronic Gas Measurement Per API Chapter 21.1
Author(s): Stephen T. Stark
Abstract/Introduction:
Gas measurement auditing has become much more complex as electronic flow measurement and other computer-based technologies have arrived on the scene. Before the early 1990s, measurement auditing was usually little more than verifying chart integration numbers and digging through piles of field test slips searching for overlooked orifice plate changes, incorrect gas quality information, and missed calibration adjustments. Today, gas measurement auditing is more complex than ever before as gas companies rely on high-speed communication and sophisticated computer networks to gather massive amounts of information required in todays fast-paced energy industry. Flow rates, total energy, pressures, temperatures, gas quality information, flow factors, meter performance data, and a lot more is included in this enormous mix of information. Much of the data collected through these systems is used for purposes other than determining gas flow. The information is also used to monitor, track, and record operating conditions relating to safety, pipeline integrity, gas management, security, and environmentally-relevant issues. Gas measurement and engineering groups sometimes support measurement audits as part of their normal responsibilities. In other cases, special audit teams do the work alone - sometimes with only training. Still, only occasionally do measurement audits extend much beyond the office walls.
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Document ID:
B9D7DB05
Auditing Liquid Measurement
Author(s): Linda A. Larson
Abstract/Introduction:
An effective audit of liquid hydrocarbon measurement is dependent upon a solid understanding of the measurement process combined with the application of sound internal auditing principles. The quality of liquid measurement activities is contingent upon (1) the reliability of the measurement equipment and instrumentation used (2) the specific procedures and practices followed in performing the measurement activities (3) the adequacy of training and proper performance of the measurement technician and (4) the proper documentation of transactions based on a measured value. All four components must be taken into consideration when auditing liquid measurement. In addition, to ensure the efficiency of the audit process, auditors must identify those areas which present the greatest risk to the organization to achieving its goals, and concentrate audit effort on those areas.
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Document ID:
CC83F125
Overall Measurement Accuracy
Author(s): Paul J. La Nasa
Abstract/Introduction:
This paper presents methods for determining the uncertainty of both differential and positive metering stations. It takes into account the type of meter, number of meters in parallel, type of secondary instruments, and the determination of physical properties. The paper then relates this information to potential influence on system balance.
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Document ID:
1E6528E0
Sarbanes-Oxley Act And Its Impact On Measurement Discussion Of The Effect Of Sox Requirements On Measurement
Author(s): Lisa Walker
Abstract/Introduction:
Sarbanes Oxley (SOX) is legislation that is here to stay. It has been five years since its implementation and SOX, though evolving, is still in place and as robust as ever. Many companies have already reviewed and implemented controls and hopefully remediated any gaps that may have existed when the audit process began. Annual reviews of controls insure that once implemented, SOX will be forever embedded in the fabric of every publicly traded company. Through the utilization of SOX guidelines strong controls have emerged which have helped establish well documented, more efficient measurement and company processes. The benefit of knowing the facets of our business from beginning to end as well as finding where any opportunities for false or even fraudulent processes may be found have been invaluable . A more evolved sense of integrity and pride in our positions and knowing exactly where our companies stand with regards to the importance of good measurement and good solid practices has been beneficial for all employees.
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Document ID:
2AE7E5ED
API Mpms Chapter 22.2 - Testing Protocol For Differential Pressure Flow Measurement Devices
Author(s): Casey Hodges
Abstract/Introduction:
The performance characteristics of a new metering device can be determined in many ways. From the testing mechanism to the formatting, analysis, and presentation of the results, a consumer can have a very difficult time determining if two meters are comparable. For differential producing flow meters, there is only one meter type that standards have been developed for, the orifice plate. These standards are based upon decades of research and development. Even orifice plate standards are continually being updated based on current technologies and capabilities. For any other differential producing meter, there was no protocol by which the performance of the meter could be quantified. This paper describes the development of API MPMS Chapter 22.2 Testing Protocol - Differential Pressure Flow Measurement Devices, demonstrates how the standard is used, and discusses issues that exist when using differential meters.
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Document ID:
4310E8C6
Overview Of AGA 7 Revision
Author(s): Angela Floyd
Abstract/Introduction:
Just when you thought you knew everything there was to know about turbine meter measurement, wham, out comes a revised AGA 7 standard. Now those basic principles are all still valid but maybe those operating practices we have built into our operating procedures need a little review. Rather than proceed as generations have done before us, research has been completed on the meters, their installation and operating practices and the way we calibrate and field test them. So now we have some data to back up our methods and madness.
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Document ID:
6AE2046B
Overview Of AGA 9 Revision
Author(s): Joel Clancy, Daniel Rebman
Abstract/Introduction:
AGA (American Gas Association) Report No. 9 - Measurement of Gas by Multipath Ultrasonic Meters was originally released for publication in June, 1998. Since that time, much has been learned and the ultrasonic meter (UM) technology has advanced significantly. Over the past several years, the AGA 9 Transmission Measurement Committee has been working on the second edition of this document. Several issues relating to AGA Report No. 9 will be discussed at length however, this paper will especially focus on the changes and additions that have been implemented in the second revision. Also highlighted will be the performance based discussions and how this has changed from the first release to the second addition. What impact do these changes have on the user? This paper will be broken down into sections that correspond directly to the AGA 9 document. In doing so it will make it easier to reference this paper against the AGA 9 Report itself. Finally, we will summarize and offer comment on the changes. Were the changes to the document good for the industry?
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Document ID:
BD145EC6
Combining Intrinsic Safety With Surge Protection In The Hydrocarbon Industry
Author(s): Don Long
Abstract/Introduction:
The Hydrocarbon Measurement Industry faces a rather unique combination of problems. First, many of the areas in and around pumping, custody transfer and storage areas are classified, or hazardous, that must, according to the National Electric Code, be assessed for explosion-proofing. This may be in the form of intrinsic safety barriers or isolators, explosion-proof enclosures and conduits, purged enclosures or nonincendive components. The second challenge facing the industry is the physical exposure of most of the electronic control and measuring systems, communications, and power subsystems, each with their own sensitive, high-performance microprocessors, etc., to potentially devastating lightning and electrical surges. Key to the successful application of both intrinsic safety (I.S.) and lightning/surge protection is proper grounding. The goal of this discussion then is to briefly summarize these two technologies and then to take a detailed look at the commonly misunderstood subject of grounding in the instrument and control system or IACS.
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Document ID:
75D842F9
Development Of Orifice Meter Standards Past(, Present And Future)
Author(s): Jane Williams
Abstract/Introduction:
Standards are developed in order to provide uniformity of action, improve efficiency, and to minimize litigation. If standards did not exist, one would have to know the dimensions (diameter, depth, thread pattern, etc.) of the socket prior to purchasing a replacement light bulb. Can you imagine the difficulties that would exist between companies if the purchaser had a set of company standards which requires that the orifice plate be installed with the sharp edge downstream and the producer had a set of company standards which requires that the orifice plate be installed with the sharp edge upstream? Measurement agreements would be very difficult to achieve in this scenario. Consequently, an orifice metering standard was necessary to avoid frequent disagreements and litigation. There are many areas of concern such as plate thickness, surface roughness, dimensional tolerances, etc that have been specified by the orifice measurement standard. If this were not the case each company would be tempted to implement whatever would benefit their company the most. Different requirements might even be employed based on whether the company was buying or selling. Thus the need for a standard was recognized many years ago.
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Document ID:
0D24BE37
Dot Qualification - Measurement & Control Technicians
Author(s): Jay Shiflet
Abstract/Introduction:
As a result of Congressional legislation, the Department of Transportation (DOT) Office of Pipeline Safety proposed the Pipeline Safety: Qualification of Pipeline Personnel - 49 CFR Parts 192 and 195 rule. The intent of this qualification rule (also referred to as the OQ rule or OpQual rule) is to ensure a qualified workforce and to reduce the probability and consequence of incidents caused by human error. The rule created new subparts in the gas and hazardous liquid pipeline safety regulations. These subparts established qualification requirements for individuals performing Covered Tasks, and amended certain training requirements in the hazardous liquid regulations. The pipeline industry worked closely with DOT to have the rule structured as a performance based rule. The rule places the compliance responsibility on the Operator. Within limitations, this permits the Operator a large measure of flexibility in the development and administration of the rules requirements.
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Document ID:
1291667F
Interface Detection In Liquid Pipelines
Author(s): Christopher B. Laird
Abstract/Introduction:
Pipelines that are used to move different types or grades of liquid petroleum face the problem of keeping these grades within their dedicated tanks. For example, a few gallons of gasoline can spoil thousands of gallons of diesel fuel. Figure 1 illustrates a pipeline that is moving three grades of products. In order to protect the integrity of a batch of liquid within the pipeline, it is necessary know where each liquid interface is within the pipeline so that tank farm valves can be properly aligned to receive the oil into the correct tank. This can be done by tracking the batch interface location based on the speed it travels through the pipeline. Obviously, interface speed is based on the liquid flow rate within the pipeline. However, experience has shown that mistakes are made in these calculations and the exact location of the interface is lost. Batching pigs can be used to provide a physical separation between batches however, this is generally inconvenient and costly.
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Document ID:
DAEFC613
Multiphase Measurement
Author(s): Richard Steven
Abstract/Introduction:
The measurement of unprocessed hydrocarbon flows is becoming more prevalent in the hydrocarbon production industry. Multiphase meters are now often integral in the design plans for new developments. However, the phrase multi-phase flow covers a huge range of flow conditions and metering these varied flows has proven a major challenge to engineers. Furthermore, due to the relatively recent arrival of these technologies on the market, and, the relatively complex and proprietary nature of the products leading to the finer details of operation not being divulged, there is often a lack of technical understanding amongst the multiphase meter users. In this paper, definitions of the phrases multiphase flow and wet gas flow will be discussed. There will be a discussion on the requirement for multiphase metering before multiphase flow patterns and the methods of predicting them are discussed. Finally, an overview of the common multiphase meter generic principles will be given.
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Document ID:
BABD6195
Odorization Of Natural Gas
Author(s): Kenneth S. Parrott
Abstract/Introduction:
In the one hundred and thirty years, or so that we have known natural gas as a fuel source in the United States, the demand for natural gas has grown at an astounding rate. There is virtually no area of North America that doesnt have natural gas provided as an energy source. The methods of producing, transporting, measuring, and delivering this valuable resource have advanced, and improved in direct relation to the demand for a clean burning and efficient fuel. While todays economic climate determines the rate of growth the gas industry enjoys, in a broad sense, natural gas is certainly considered essential and a fuel of the future. Of primary importance, in the process of delivering gas for both industrial and public use, is providing for the safety of those who use it. Whether in the home, or workplace, the safety of all who use or live around natural gas systems is of primary concern. Natural gas is a combustible hydrocarbon and its presence may under certain conditions be difficult to determine. One need only to remember the tragic explosion of the school building in New London, Texas in the 1930s to understand the potential for injury when natural gas accidentally ignites. Because of this possibility for accidents, regulations have required the odorization of natural gas when it comes in contact with the population. This enables people living and working around natural gas to detect leaks in concentrations well below the combustible level of the natural gas.
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Document ID:
080380BF
Orifice Meter Tube Dimensional Tolerances
Author(s): Ken Embry
Abstract/Introduction:
The orifice meter is the most predominantly utilized device for measurement of natural gas. Its dominant presence in the natural gas industry stems from many years of acceptance as the primary means for accurate measurement. In 2000, revised manufacturing and inspection standards, along with new technology for flow enhancement have improved the overall accuracy of orifice metering. Though other measurement devices and technologies have made significant impact, the orifice meter offers stands as the dominant device for several reasons: - Rugged construction that stands up to many applications - No moving parts involved in the measuring process - Relatively inexpensive to manufacture and maintain - Proven and accepted technology - Dimensional calibration is accepted in lieu of flow calibration Proper design / testing procedures and accurate determination the actual dimensions of an orifice meter is key to ensuring that the device performs with minimum uncertainty.
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Document ID:
EC9BF923
Program For Training A Measurement Technician
Author(s): Allen N. Chandler
Abstract/Introduction:
The need for quality measurement has increased dramatically in the past several years. Deregulation of market pricing structures, open access markets, increased exploration and drilling costs, fierce competition, and new regulatory requirements have all influenced todays approach to quality measurement methodologies. In fact, the terminology has evolved from gas volume measurement to total energy measurement. Today not only is the volume of gas a consideration, but also the quantity of energy the gas produces. Our industry has transitioned from the MMCF to the MMBTU for gas measurement. As technology has advanced, there has been a greater sense of urgency for employee training. The open-access market, which moves greater quantities of natural gas volumes with considerably lower profit margins, became a reality in the mid- to late-eighties. Measuring stations at transportation connects required a degree of accuracy that necessitated measurement personnel skilled in new technology.
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Document ID:
67D0B2BC
Vortex Shedding Meters
Author(s): Paul Warburton
Abstract/Introduction:
Vortex meters have proven to be repeatable, accurate and reliable flow meters for liquid, steam, and gas measurement applications. They provide turn down ratios as high as 30:1, low-pressure drops and no moving parts resulting in calculated mean time between failures (MTBF) exceeding 250 years. Recent advances in technology have dramatically improved meter performance, including those applications with inherent noise, making the vortex meter a viable choice for industry, and one of the fastest growing meter technologies in the world.
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Document ID:
D0768716
The Effects Of Additives On Metering In Liquid Pipelines
Author(s): Joseph T. Rasmussen
Abstract/Introduction:
Todays refined fuels are formulated using a recipe of chemical blending and complex processing. Current blends that make-up fuel & chemicals introduce new problems that challenge product quality and performance. Refined products can be altered or degrade prior use by secondary forces such as environment and handling. A wide range of performance and handling problems are minimized or resolved by use of chemical additives. Additives to fuel products are often included in the refining processes that address these problems. Fuels may require additional blending of additives separate from the refining process. The effect these additives have on liquid metering is variable based on their composition and concentration. Pipeline and terminal metering systems must adjust to the varying properties the additives introduce to the liquid. This paper highlights the effects some common & not-so-common fuel additives have on liquid metering systems.
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Document ID:
9787FBCF
Meter Selection
Author(s): Harvey Stockman
Abstract/Introduction:
Natural gas meter selection is based on a variety of factors: the most important of which are safety and accuracy. Other significant factors include repeatability, defensibility through adherence to contractual and/or regulatory requirements and industry standards, cost effectiveness, reliability, and uniformity with existing installations. This paper will briefly discuss commonly used high pressure gas meters, their basic functionality, applicable standards, installation and operating considerations based on the authors experience and a review of industry standards and literature, their turndown or range-ability, and specific examples of recent meter selections for specific applications.
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Document ID:
19B9F052
Cone Meters For Liquid And Gas Measurement
Author(s): Philip A Lawrence
Abstract/Introduction:
This paper will describe how cone meters whilst similar in principle differ operationally from other types differential pressure type meters and how they are used for the measurement of liquid and gas. The cone meter has become synonymous with specialist metering applications over many years due to special traits that are inherent in this type of meter design. The original concept taken from the Venturi meter will be mentioned in the paper for first principle purposes. Use of a cone meter on Steam, Wet Gas , Liquids that have trash, asphaltenes, wax in pipes, installation issues such as short meter runs lengths (usually off-shore), and custody transfer with user-party agreement have all been quite successful through the years. Some of the key ideas to enable some of these applications will be shown in this paper. Trade Marks or Trade Names will not be mentioned in this paper as per ISHM guidelines.
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Document ID:
00E334FA
Measurement Scene Investigations
Author(s): Chris Spriggs
Abstract/Introduction:
Oklahoma Natural Gas Company, one of three companies that make up the Distribution Division of ONEOK, Inc., provides natural gas distribution services to 80% of Oklahoma or approximately 850,000 total customers. This customer base includes service to more than 50,000 commercial and industrial customers. Many of these commercial and industrial customers now have the opportunity to buy their gas on the open market. Oklahoma Natural Gas currently allows any customer, (other than residential), that uses over 1,000 Dth/year to be eligible to participate in our gas transportation program. At this time about 5,000 customers participate. In the future, the company is considering the expansion of this opportunity to all customers.
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Document ID:
0667D8D5
About Ishm 2008
Abstract/Introduction:
Collection of documents about ISHM including table of contents, event organizers, award winners, committee members, exhibitor and sponsor information, etc.
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Document ID:
B575C7DD