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 regulation (M&R) will be addressed.
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Document ID:
009DB091
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:
E80B569A
Design Of Distribution Metering And Regulating Stations
Author(s): Edgar Wallace Collins Jr.
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:
46D18574
Determination Of Leakage And Unaccounted For Gas - Transmission
Author(s): Alan Mcarthur, David Furry
Abstract/Introduction:
Gas transmission pipeline leak detection is required under the Pipeline Safety Improvement Act of 2002 (HR3609). With gas prices reaching historical high values the cost savings to be made through the detection and repair of transmission pipeline leaks has joined with pipeline safety as a major economic driver for new pipeline leak detection technologies. Major technological advances have been made in recent years in the field of gas leak detection through the use of Infra Red (IR) gas detection optical cameras. This paper will review some of the technologies currently employed in gas leak detection surveys of transmission pipelines. In addition it contains a short review of the Infra Red (IR) gas leak detection methodology and compares the Passive IR with Active IR approach. It will conclude with an example of the cost benefit of an effective transmission pipeline gas leak detection program.
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Document ID:
14D6F042
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 determine how much energy is bought and sold and how much a company is paid for transporting the gas. The value of accurate flow metering has never been higher than it is today. One of the most common and difficult to identify errors in metering is that caused by pulsating flow. Periodic unsteady flows, known as pulsating flows, can produce measurement bias errors in all types of gas flow meters. It is important to understand the effects that pulsations have on the common flow meter types used in the gas industry so that any result measurement inaccuracies can be identified and avoided. It is also essential to identify ways to control the effects of pulsation by reducing pulsation amplitudes or by eliminating pulsation with properly designed acoustic filters. This paper describes the effects of pulsation on orifice, turbine, ultrasonic, and a few other flow meter types. 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, are also provided.
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Document ID:
F20DD7A9
Effects Of Abnormal Conditions On Accuracy Of Orifice Measurement
Author(s): Thomas B. Morrow
Abstract/Introduction:
In 1971 E. J. Burgin of Florida Gas Transmission Company presented a paper at ISHM entitled Factors Affecting Accuracy of Orifice Measurement (Primary Element). Burgin noted that AGA Report No. 3 (of that time) claimed that an orifice meter with flange taps and with a diameter ratio, , between 0.15 and 0.7, fabricated and operated in accordance with the specifications in the standard, would have a discharge coefficient value within 0.5% of the value calculated from the orifice equation. The purpose of Burgins paper was to examine some of the specifications in the orifice meter standard and to review the effect upon measurement accuracy when the specifications are ignored. Burgin reviewed data from tests sponsored by the AGA Gas Measurement Committee during the period 1925- 1930 as well as additional field-test data taken at Florida Gas Transmission Company. Kemp summarized several of the most significant orifice measurement errors on one page. Every entry on Kemps list is an undermeasurement error. That is, the actual gas flow rate exceeds the indicated flow rate. The magnitudes of the under-measurement errors ran from less than 1% to from 10% to 25%. There is a large financial incentive to avoid the kinds of abnormal conditions that produce errors of this magnitude.
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Document ID:
6CB3F604
Fundamentals Of Gas Measurement I
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:
78A380B1
Fundamentals Of Gas Measurement II
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.
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Document ID:
0D027E7E
Fundamentals Of Gas Turbine Meters
Author(s): John A. Gorham
Abstract/Introduction:
The majority of all gas measurement used in the world today is performed by two basic types of meters, positive displacement and inferential. Positive displacement meters, consisting mainly of diaphragm and rotary style devices, generally account for lower volume measurement. Orifice, ultrasonic and turbine meters are the three main inferential class meters used for large volume measurement today. Turbines are typically considered to be a repeatable device used for accurate measurement over large and varying pressures and flow rates. They are found in a wide array of elevated pressure applications ranging from atmospheric conditions to 1440 psig. Turbine meters have also become established as master or reference meters used in secondary calibration systems such as transfer provers. A significant number of both mechanical and electrical outputs and configurations have become available over the past 50 years of production. This paper will focus on the basic theory, operating principles, performance characteristics and installation requirements used in turbine meter applications. A discussion of fundamental turbine meter terminology is also included.
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Document ID:
3516A33A
Fundamentals Of Orifice Meter Chart Recorders
Author(s): David E. Pulley
Abstract/Introduction:
What is an orifice recorder? The answer usually depends upon who is providing the response. The term orifice meter can mean everything from the orifice plate to the entire meter station. The American Gas Association defines the orifice meter as the complete measuring unit comprised of primary and secondary measurement elements. The primary element consists of an orifice meter tube constructed to meet the minimum recommended specifications of the measurement authority contractually agreed upon by two or more parties. The secondary element consists of equipment that will receive values produced at the primary element. The values may be measured and recorded onto circular paper charts or received by electronic flow computers that calculate a volume on-site, to be retrieved as desired. This paper addresses the Orifice Meter Chart Recorder and endeavors to explain its fundamental workings. The American Gas Association does not specify a particular manufacturer or type of recording instrument to be employed. The person selecting the instruments installed at a metering station should answer the following questions about the instruments.
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Document ID:
1EC0CD25
Installation And Operation Errors In Gas Measurement
Author(s): Thomas B. Morrow
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:
127A1C8C
Low Pressure Gas Measurement Using Ultrasonic Technology
Author(s): Daniel J. Rudroff
Abstract/Introduction:
With the increased use of natural gas as a fuel, higher natural gas prices, and new federal regulations, all buyers and sellers of natural gas are looking at ways to improve their natural gas measurement and reduce maintenance and the unaccounted for natural gas.
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Document ID:
BC6AAD2B
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:
58EFEC22
Measurement Station Inspection Program And Guide
Author(s): Robert J. Rau, Consultant
Abstract/Introduction:
Today, lets discuss an important phase of everyday planning for the Measurement personnel. A test and inspection guide is a corporations plan to meet government regulations. DOT requires pipelines to have a written operating and maintenance plan. This plan must meet the minimum federal standards and cover various phases of operations. A company may include items above the minimum federal standards but they must operate according to the plan they prepare. In plain words, what you write you must be ready to live and operate by whether they just meet the DOT minimums or exceed the DOT requirements and this becomes the company bible. The last item to remember is that as field personnel you must perform the required inspections, complete properly the administrative records to document and prove that required tests were made. This is an important item as it involves personal honor and your signature is your statement the work was done. Government penalties applied to companies can be very high if the required work is not done, or has not been properly documented. If the work is not done, admit an error was made. It helps with DOT inspections if an explanation is in the file as to why the specific test was not performed, such as weather prevented transportation offshore or station shut in because well is dead.
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Document ID:
C0AAB3E6
Multi-Path Ultrasonic Meters For Custody Transfer Natural Gas Measurement
Author(s): Martin Schlebach
Abstract/Introduction:
In the past ten years the use and acceptance of Ultra Sonic Meters (USMs) to measure high pressure natural gas has risen exponentially. Not only has the technology been used in retrofitting or adding stations on existing pipelines, but it was the technology used on the latest major new pipelines constructed in recent years. There have been several reasons for the increased acceptance, the first was the release of AGA report #9 and related standards that deal with the use of USMs in custody transfer measurement. These standards coupled with the meters inherent advantages have propelled the USMs to their current level of acceptance. These advantages include no pressure drop, low capital costs for larger sized meters (10?), high turndown ratio (80-1) and little or no periodic maintenance. With the decreasing size of most maintenance departments, the ability to lower, even eliminate periodic site visits has become increasingly important. This was a huge point of consideration when one of the new pipelines decided to use USMs, even in smaller sizes where the price is higher than other metering technologies, The potential saving in OPEX greatly outweighed the initial CAPEX.
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Document ID:
45760BFB
Orifice Fittings And Meter Tubes
Author(s): Bob Carlson
Abstract/Introduction:
Throughout the oil and gas industry, there stems the need for accurate, economical measurement of process fluids and natural gas. Orifice Meters sometimes referred to as Orifice Fittings satisfies most flow measurement applications and is 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:
983D3FBF
Orifice Meters Operation And Maintenance
Author(s): Ken A. Hudgeons
Abstract/Introduction:
Orifice Meters are an integral part of the total process in determining the value of Natural Gas that is being bought and sold. Any part of the system which is outside the AGA 3 or Manufacturers tolerances can lead to inaccuracies and additional uncertainties which in turn lead to incorrect revenues. With the market prices being paid for Natural Gas, errors which in the past may have been deemed insignificant, are now reason for concern. The job of the measurement technician is to maximize the return on investment while utilizing the equipment in place. This in turn insures both the producer and the purchaser are receiving fair value for the product being measured. With proper operating and maintenance procedures in place, accurate results through the use of orifice measurement can be achieved.
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Document ID:
04426B21
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.
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Document ID:
54F43D15
Wet Gas Measurement
Author(s): Joshua J. Kinney
Abstract/Introduction:
In the natural gas industry, proper flow measurement is one of the key elements in providing accurate allocation of revenue. Natural gas may have some liquid content. This liquid may be water, hydrocarbons, compressor oil or a mixture of all three. When a flow meter is subjected to wet gas, large errors in flow measurement may occur with undesirable results to the bottom line. The intention of this paper is to introduce the reader to the difficulties associated with wet gas measurement and identify some techniques being used accomplish this. The content presented is not intended for wet gas measurement error correction. The first section gives a brief glossary of terms used when describing wet gas flow followed by a list of general equations associated with these terms. The next section gives descriptions wet gas flow regimes present in a horizontal pipe. Previous research conducted in a controlled environment is presented focusing on the effect of entrained liquids on various flow measurement devices. In addition, methods of wet gas flow measurement are discussed. Finally, general ideas about wet gas metering are discussed.
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Document ID:
2A9DE663
Contaminant Accumulation Effect On Gas Ultrasonic Flow Meters
Author(s): Jeff Gorman
Abstract/Introduction:
During a standard ultrasonic meter calibration at a flow laboratory testing facility, variances with the error percentages were noticed. Upon further inspection, an accumulation of a waxy substance had coated the internal diameter of the meter tube, flow conditioner and ultrasonic meter transducers. This paper discusses the problems associated with contamination accumulations and presents the data gathered from the initial test versus the final test and calibration after the meter tube assembly had been cleaned.
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Document ID:
D441F978
Application Of Densitometers To Liquid Measurement
Author(s): Colin B. Blakemore
Abstract/Introduction:
One of the many parameters that must be accurately measured for product quality control, custody transfer, process control, or liquid interface detection purposes is liquid density. Often, density measurement is combined with flow measurement to determine the mass flow rate of a liquid in a pipeline. In this article, we will discuss the principle of operation of vibrating tube densitometers, design suggestions for densitometer installation, and calibrating, or proving, the system.
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Document ID:
0673FD22
Application Of Turbine Meters In Liquid Measurement
Author(s): Don Sextro
Abstract/Introduction:
Turbine meters are found around the world measuring crude oil, intermediate and finished products, and light hydrocarbons such as ethane, propane, butanes, and natural gas liquids (NGL) mixtures. Their performance and durability have enabled turbine meters to be used for custody transfer, check and operational measurement in the petroleum industry. In custody transfer applications, there are a number of industry standards to guide a user in the design, construction, operation and maintenance of the turbine meter and its associated equipment. This paper presents the issues associated with applying turbine meters in liquid hydrocarbon measurement from the perspective of a user who needs to select and install a meter for custody transfer purposes. For non-custody transfer applications, a user may consider following the standards and practices applied to custody transfer meters to achieve accurate results and reliable operation.
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Document ID:
EB643F81
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. This paper will address the calculation procedures for petroleum quantities under flowing and non-flowing conditions. The same attention to detail and precision used in determining the primary measurement values (such as temperature and pressure) must be applied to the calculation procedures to maintain the same level of precision.
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Document ID:
51DBB019
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. Often only the smaller streams flow rate is varied whereas the larger is kept constant. The ratio of the two streams depends upon a controlling parameter that is monitored downstream of the common injection point. Such monitoring can be performed automatically using on-line analytical equipment or manually by collection of samples. The manual collection method can provide a semi-automatic operation at best. The injection rate of the smaller stream is based upon the sample analysis. An improvement in this application would be a ration control system where the flow rates of both streams are measured and the analysis from the manual sample determines the setpoint for the ratio. This is beneficial where the flow rate of the larger stream tends to vary.
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Document ID:
B0C87972
Crude Oil Gathering By Truck - Metering Versus Manual Gauging
Author(s): John Frank
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:
35DF7EEF
Design, Operation And Maintenance Of Lact Units
Author(s): James King
Abstract/Introduction:
This paper presents an overview of the design, operation and maintenance of Lease Automatic Custody Transfer (LACT) units. These units are used for the automatic unattended measurement of quantity and quality of crude oil and sometimes other wellhead liquids when transferred from a producer to a pipeline for the account of a purchaser or consignee. This transfer usually takes place at a production lease site, hence, the use of Lease in the name. This can be on land or offshore delivering into pipelines, barges, or tanker loading and offloading operations. Similar units used to measure the transfer of other liquids or liquids between pipelines are often called ACT units since they usually are not associated with a crude oil production lease. LACT units can range from small single meter, low pressure systems with portable proving connections to highpressure systems with multiple meters and an on-site dedicated meter prover. Multiple smaller meters in parallel, instead of a single large meter, permit a larger range of permissible flow rates and reduces the prover size. Additionally, if one meter run fails, the LACT Unit can still operate at a somewhat lower capacity.
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Document ID:
C62D2B10
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:
322C3D80
Effects Of Flow Conditioning On Liquid Measurement
Author(s): Philip D Baker
Abstract/Introduction:
The main objective of this paper is to provide a summary to-date of the API Liquid Flow Conditioning Research Program. Insight is provided into the effects on liquid turbine meter accuracy of flow disturbances, caused by obstructions on strainer screens, for various upstream piping geometries and different types of flow conditioners. This research program was initiated by the API Committee on Liquid Measurement (COLM) in 2005, and is continuing during 2006, primarily because of several different field observations that sometimes debris on a strainer screen can cause a significant shift in the meter factor (MF) of turbine meters, which is eliminated when the debris is removed from the strainer. Turbine meter MF shifts of up to 0.25% have been observed in the field due to debris on the strainer screen, when using tube bundle type flow conditioners. The main objectives of this research program were to: (1) Try to duplicate in the laboratory the problem observed in the field (described below), using conventional tube bundle type flow conditioners, (2) determine if the new isolating and/or high performance type flow conditioners eliminated, or substantially reduced, the problem, (3) determine the magnitude of MF shift when using just 20 diameters (20D) of straight pipe as a flow conditioner, and (4) determine if different meter run inlet piping geometries (i.e., straight pipe, elbows in-plane, and elbows out-of-plane) have an effect on the MF shifts obtained using the various flow conditioners.
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Document ID:
A31F9FEB
Polymer-Grade Ethylene Measurement
Author(s): James E. Gallagher
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:
66AF18B6
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:
7D1B959F
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:
14B300B9
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:
C9C2A709
Fundamentals Of Liquid Turbine Meters
Author(s): James H. Smith
Abstract/Introduction:
Turbine meters have been used for the custody transfer of refined petroleum products and light crude oils for over 30 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 PD meters for higher viscosities. However, new developments in turbine meter technology are pushing these application limits while increasing reliability and accuracy. This paper will examine the fundamental principals of turbine meter measurement as well as new developments including: smart preamps for real-time diagnostics, helical flow turbine meters for higher viscosity applications, higher performance flow conditioners to increase accuracy and viscosity compensation to extend the application limits.
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Document ID:
34332912
Gauging, Testing And Running Of Lease Tanks
Author(s): George L. Lewis
Abstract/Introduction:
Gauging is a measurement procedure whereby the QUANTITY and QUALITY of the crude oil are determined at the point of sale by a company gauger or other designated representative, such as a Crude Oil Truck Driver (COTD). Typically, we think of lease tanks as having volumes of less than 1,000 barrels. The gauger is primarily responsible for rejecting non-merchantable crude oil and buying accurate volumes of merchantable crude oil that can be refined, traded, or sold. His company is fully dependent upon his competence and sound judgment, while his high public visibility requires him to be conscientious, accurate, professional, and courteous.
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Document ID:
41E1D5F8
Helical Turbine Meters For Liquid Measurement
Author(s): Joshua W. Rose
Abstract/Introduction:
Turbine meters have been used for the custody transfer of refined petroleum products and light crude oils for over 30 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:
6AB85EE3
Installation And Operation Of Densitometers
Author(s): Eric Estrada, Don Sextro
Abstract/Introduction:
A densitometer is an electromechanical device used to measure the density of a flowing stream. Because it measures density, a densitometer is often called a density meter. This paper uses densitometer and density meter interchangeable. The stream to be measured is usually a single-phase liquid, but instead could be a single-phase gas or vapor. In the oil and gas industry, a densitometer usually measures the density of liquid hydrocarbon finished products or liquid mixtures. Other industries use densitometers to measure the density of fluids like milk, vinegar and syrup. As an electromechanical device, the densitometer uses electrical power and a mechanical arrangement of tubing, tuning fork or a float and chamber to measure the density of the fluid flowing through the device. The densitometer transmits an electrical signal representing the measured density. Density can be measured either continuously or in discrete batches such as would be the case with a spot sample. Many of the density measurements taken in the oil and gas industry are determined by continuous densitometers. These densitometers are commonly installed on a meter skid and have a least a portion of the flowing stream flowing through them. Measuring density is discrete batches generally occurs in a pycnometer proving, a weigh tank or when using a hydrometer. If stream composition changes frequently or unpredictably, a continuous densitometer is appropriate.
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Document ID:
34DEE7AA
Leak Detection On Petroleum Pipelines
Author(s): Mike Wheeler
Abstract/Introduction:
Leak Detection efforts at pipeline companies are driven by the need of complying with government regulations and by the companies desire to be a safe and environmentally conscientious pipeline operator. The U.S. Department of Transportations Office of Pipeline Safety (DOT-OPS) regulates the transportation of hazardous liquids under the Code of Federal Regulations as legislated through the Pipeline Safety Act and its reauthorizations (49 CFR 195). In this regulation it is stated that An operator must have a means to detect leaks on its pipeline system. An operator must evaluate the capability of its leak detection means and modify, as necessary, to protect the high consequence area. Missing in this regulation is some standard for what is sufficient leak detection means for the high consequence area (HCA). Along with the DOT, the Minerals Management Service (MMS) is requiring leak detection on systems offshore of the U.S.
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Document ID:
A3EA1DA8
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. One of the major differences between the two is that the Audit verifies that the established procedures are being followed, while the Measurement Survey verifies the procedures are indeed the correct procedures for the specific task, not just are they being followed.
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Document ID:
D1D482EB
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. This paper outlines design considerations and other factors that should be considered in specification and construction of flow measurement stations for hydrocarbon liquids.
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Document ID:
51EE6CDF
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:
3BC16C66
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:
785E7565
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:
26039365
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:
93060858
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.
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Document ID:
6B744CF6
Measurement Methods For Liquid Storage Tanks
Author(s): Harold L. Gray
Abstract/Introduction:
A brief discussion on Methods for Determining Volumes in Liquid Storage Tanks. This will include tank gauging methods and errors that can occurr. Tanks strapping methods and pitfalls associated. Methods for determining temperature of the liquid and tank shell temperature. Gravity determination. And finally sampling methods for S&W content and quality of the liquid, for ticketing purposes.
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Document ID:
26F21A51
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:
EBB587C8
Operational Experience With Custody Transfer Ultrasonic Meters
Author(s): Kevin m. Malek
Abstract/Introduction:
The use of ultrasonic meters requires an open-minded approach to measurement. I was not in the measurement industry when the turbine meter was introduced, yet I imagine their introduction did not come without challenges. Mechanical provers became common while the use of tank provers became less desirable. Measurement methods began to change, and today we are experiencing a similar evolution in measurement and calibration. Like displacement and turbine meters, ultrasonic meters measure various mediums with the same accuracy when calibrated. However, they are more sensitive to flow rate disturbances than either of the other measurement systems. Installation and calibration methods are critical for accurate performance.
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Document ID:
D989DE87
Orifice Meters For Liquid Measurement
Author(s): Fred Van Orsdol
Abstract/Introduction:
Orifice meters have been in common use for many decades, but in the energy industry their use has been primarily in gas metering systems. This is interesting, in that much of the research to develop orifice meter factors (discharge coefficients) has been performed using oil, water, steam and air, as well as natural gas. Orifice meters used in liquid measurement provide good accuracy without the requirement for meter proving as long as they are properly designed, installed, calibrated and maintained. If higher levels of accuracy or wanted, they can be proven using appropriate software and hardware and traditional meter proving systems.
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Document ID:
F92E3FB9
Pycnometer Installation, Operation And Calibration
Author(s): Harold L. Gray
Abstract/Introduction:
The process of installing Pycnometers for the purpose of calibrating a density meter. The process of field verifying pycnometer calibrations. Experiences in verifying flow through the pycnometer and ways of achieving temperature equalization in both the density meter and the pycnometers. A discussion of the types of pycnometers and the differences in design. A brief discussion on the ways to install the pynometers. The density meter and the way it is installed can and should determine the installation of the pycnometer. Allowances in the piping should given to measure the temperatures in both the density meter and the pycnometer. The same should be integrated for the measurement of pressure as well. Safety considerations should govern all designs. And all parts of the calibration process. A discussion of the data that is supplied with the Laboratory Calibration A very brief discussion on the field verification process in accordance with API MPMS Chapter 14.6 Continuous Density Measurement. A step through of the calibration process including the calculations necessary to complete the process.
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Document ID:
BCFDE35F
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. To assist in accomplishing this, you need to consider training and developing field personnel in measurement control practices. Then you must support them with expertise in API Manual of Petroleum Measurement Standards (MPMS) and corporate practices and policy. You should also ensure the most effective technologies are used and remain aware of philosophical industry trends.
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Document ID:
476E1768
Troubleshooting Liquid Pipeline Losses And Gains
Author(s): Joseph T. Rasmussen, Michael R. Plasczyk
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 gains and losses employs tools and analysis methods developed specifically to troubleshoot pipeline variances. Examination of pipeline gains and losses uses some basic statistical tools as well as intuitive and creative insight into what controls gains and losses. The basic tool for evaluating system performance is Loss/Gain which is 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 than does leak detection. 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 possible corrective actions.
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Document ID:
E00C48F7
Ultrasonic Meters For Liquid Measurement Characteristics Of Doppler And Transit-Time Ultrasonic Liquid Flow Meters
Author(s): Steve Yon
Abstract/Introduction:
This paper is a review of the state-of the-art, design and operational performance characteristics of Doppler and transit-time ultrasonic (UFM) liquid flow meters. Ultrasonic meters of various types have been used in our industry for over 20+ years. There are generally two different types of meter technology, transit-time and Doppler. Doppler was the first technology and was considered to be an alternative to conventional flow measurement. You could just ?stick it on the outside of the pipe and measure ? like magic. Their ?performance? however, in the end proved questionable. Accordingly, for many years the ?Doppler? and ultrasonic names did not enjoy the privilege of being considered an accurate measurement device. The continuing enhancements of Doppler technology and the development of transit time technology have dramatically changed the ability UFMs to measure accurately. Beginning in the mid 1980s transit time technology emerged and has been applied with very successful results. In January, 2005 API approved and published the first edition of Chapter 5.8 ?Manual of Petroleum Measurement Standards for Measurement of Liquid Hydrocarbons by Ultrasonic Flow Meters Using Transit Time Technology. This has officially cleared the way for Custody Transfer Ultrasonic Measurement.
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Document ID:
44408755
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:
11632C93
Proving Liquid Meters With Microprocessor Based Pulse Outputs
Author(s): Kenneth D. Elliott
Abstract/Introduction:
Have you ever wondered why your latest microprocessor based flowmeter measuring liquids refuses to be proved? Why is it sometimes impossible to achieve the run-to-run repeatability that the API mandates? By reviewing tests performed by an API task group, this paper attempts to shed some light on what probably is the cause, and also suggest what actions you should take to make your Coriolis or Ultrasonic flowmeter easier to prove. Flowmeters utilizing microprocessors have many advantages such as self-diagnostic checks and no rotating parts. The diagnostic data is important because it can warn of impending failures before they have a major impact on the measurement. These flowmeters however are substantially different from other primary devices because of their reliance on the accompanying secondary electronics.
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Document ID:
D964ED83
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 beginning to displace 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 But unlike many mechanical meters, UFMs have had more difficulty in proving according to API Chapter 4.8.
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Document ID:
C528A58A
Accuracy Diagnostics Of Liquid Ultrasonic Flow Meters
Author(s): Christopher B. Laird
Abstract/Introduction:
Ultrasonic flow meters have gained industry acceptance for many applications including custody transfer. Custody transfer applications were made possible when in October 2002 API Committee on Petroleum Measurement published the Draft Standard entitled Measurement of Liquid Hydrocarbons by Ultrasonic Flowmeters Using Transit Time Technology. In October, 2004, a slightly revised version of this draft was accepted as a full standard (Chapter 5.8) for inclusion into the API Manual of Petroleum Measurement Standards putting this technology on a par with PD meters, turbine meters and Coriolis meters. This paper will delve into some of the ways the ultrasonic flow meters are changing the techniques for precision petroleum measurement.
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Document ID:
2987A6AF
Advanced Application Of Flow Computers And Telemetering Systems
Author(s): Damon Ellender
Abstract/Introduction:
In the past few years, Digital Plant Architectures have proven their value by providing improved plant operations by increasing throughput, availability and reducing maintenance costs in process plant installations worldwide. On the whole, industries such as the Oil and Gas, Water, and Wastewater industry has not benefited from these advancements, due largely to the logistical challenges posed in implementing the architecture over large and remote geographical areas. Among these challenges are utility availability, communications infrastructures, and availability of local expertise leading to prohibitive costs. Utilizing electronic measurement techniques to collect data at each remote site is important for accurately reporting the remote process in real-time. And, Supervisory Control and Data Acquisition (SCADA) software allows high visibility for managing and optimizing these remote processes. This real-time visibility would be almost impossible to achieve with paper charts and pneumatic instrumentation alone. Advancements in technology now make it possible to integrate remote sites into a Digital Field Architecture, or virtual plant, occupying hundreds or thousands of square miles.
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Document ID:
05500186
Application Of Flow Computers For Gas Measurement And Control
Author(s): King Poon
Abstract/Introduction:
Flow computers are microprocessor controlled CPUs specifically designed to measure and regulate the transfer of a fluid from one point to another. They are an essential part of electronic fluid flow measurement, and are usually installed in various remote locations throughout the production, transmission and distribution segments of the gas industry. The function of a flow computer is fourfold: collect measurement data, calculate and store measurement data, transmit stored measurement data to a host system, and execute control requirements. In addition to measurement data, the event log, audit trail, and alarm information is also collected, stored, and subsequently transmitted to a host system in accordance with API Ch 21.1 - Flow Measurement Using Electronic Metering Systems. All these flow computer functions are controlled by on-board firmware, sometimes in conjunction with inputs from the host system. It is this on-board firmware, and associated host software, that allows the user to maximize the flow computers versatility and efficiency.
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Document ID:
0F1B4220
Applications Of Portable Computers And Software
Author(s): Cameron R. Spitzer
Abstract/Introduction:
Laptops, handhelds, palmtops and PDAs are becoming common in the Natural Gas Industry to perform a variety of portable computer functions. Applying these different technologies to fit a given task is sometimes not immediately apparent. Portable Computers do make the field users job easier to perform, if time is taken to assure that they are selected to fit the application. Emphasis in this paper will be on mobile computing as it relates to the Natural Gas Industry.
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Document ID:
CE7913C7
Basic Applications Of Telemetring Systems
Author(s): Jim Griffeth
Abstract/Introduction:
Telemetering is the process of transferring data measured, calculated, or monitored over a distance or from point A to point B. One of the first forms of telemetry developed was used to determine pressures and flows of natural gas pipelines. It was popular during the 70s and 80s. This type of telemetering used a process known as pulse duration. Pulse duration is a process of a pulse being transmitted over a set period of time to indicate a variable. For example, the first times were based on a 3-15 second time interval. A 3-second pulse provided a measure of 0% of scale and a 12-second pulse provided a measure of 100% of scale. Why start at 3 seconds? This provided for a true 0 if the pulse was less than 3 seconds the processor could determine that the value was actually less than 0%. The 15-seconds provided for a true 100%. These pulses were usually passed through dedicated phone circuits to a central point where the data was presented in the form of charts on recorders for monitoring. This was a great improvement over previous operating schemes because it provided real time data. The data accuracy varied, however, due to temperature and distance of the wiring used for transmission.
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Document ID:
11CE09D4
Basic Electronics For Field Measurement
Author(s): Dale Gary
Abstract/Introduction:
This paper is written with the idea of presenting basic electronic principles and how to apply these to common applications in the oil and gas industry.
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Document ID:
FCB1791A
Scada Systems
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:
C23D172F
Communication Systems For Gas Measurement Data
Author(s): Ben Hamilton
Abstract/Introduction:
Communications systems range from the simple to complex, we have a lot of choices to make! Making the best choices and avoiding the pitfalls can mean the difference between success and failure. Many good papers describe the SCADA system, this discussion is focused on the connectivity between the SCADA server (Master Terminal Unit), Remote Terminal Units or Electronic Flow Meter (EFM) and Programmable Logic Controller (PLC). The trend is to locate the SCADA server in a data center or business office, remote from the production field or pipeline. This trend creates demands for connectivity options. The business reality is that we must use capital wisely and control recurring cost while providing the service that our internal and external customers demand. Connectivity must be well documented and maintainable. We must be able to define the quality of the connection and measure it (you cant manage what you cant measure). The connections to remote equipment may be isolated in hard to reach locations and they may be relocated from time-to-time. These and many other considerations may appear to make our decision making task impossible. The reality is that we dont have to choose a single option for all needs. In fact, complex systems usually rely on numerous connectivity methods. Some of the options are described here.
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Document ID:
34E241FB
Communication To Measurement Equipment At A Gas Distribution Location
Author(s): Chris Spriggs
Abstract/Introduction:
Deregulation of the natural gas industry over the last several years has created change to our gas measurement processes as never before and increased the complexity to the way we do our business. With the unbundling of services, customers of all sizes are opting to choose their own gas suppliers, and when people need to make choices they demand information on which to base those choices. This new environment has created a widespread need for gas volume information on a more frequent basis to multiple parties. Today, its not just the pipeline companies that need to know the meter readings, but also the customers, brokers, and suppliers. Customers demand for timely information has accelerated gas distribution companies shift to electronic technologies especially those involving communications. Little antennas are popping up all around gas facilities. Meters are being read remotely and their data is communicated to a measurement data processing group via many varied communication paths.
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Document ID:
857C0929
Economics Of Electronic Gas Measurement
Author(s): Shawn Kriger
Abstract/Introduction:
Electronic flow computers (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 existing 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.
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Document ID:
CEB1E606
Effects Of Cathodic Protection And Induced Signals On Pipeline Measurement
Author(s): Peter P. Jakubenas
Abstract/Introduction:
The effects of cathodic protection and other induced signals on pipeline measurement equipment can be quite profound. This paper will explore the sources and effects of induced signals, and the prevention of undesirable induced signals in custody transfer measurement equipment.
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Document ID:
F3E415C3
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. API Chapter 21.1 provides the algorithms for all aspects of natural gas measurement for custody transfer. This includes calibration algorithms, calculation methods, historical record content, audit trail considerations as well as installation issues. The standard addresses orifice and turbine/linear measurement. While ultrasonic meters are not specifically addressed in the standard, it has become customary to treat them as turbine meters for measurement purposes. This paper will focus on calculation algorithms, record management and calibration methods.
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Document ID:
2B355970
Application Of Flow Computers For Gas Measurement And Control
Author(s): Jerry Van Staalduine
Abstract/Introduction:
Electronic flow computers (EFCs) have become the standard for real-time gas measurement. As these devices become more and more capable, advanced control strategies are becoming common place. As more and more EFCs are commissioned, operators sometimes learn hard lessons regarding electronic gas measurement. Many times these lessons could have been avoided if proper consideration was given to the selection of an EFC devise and the applications at hand. This paper will discuss, in general, gas measurement and control applied through EFCs. It will focus on the importance of AGA EFC configuration, API Chapter 21 historical archiving techniques, and the different control options available.
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Document ID:
D7CF313C
Spread Spectrum Systems For Efm And Scada
Author(s): Bill Frachiseur
Abstract/Introduction:
In 1985, the FCC (Federal Communications Commission) allocated three frequency bands for a radio transmission technique known as spread spectrum communications, originally developed by the military. This transmission technique has much greater immunity to interference and noise compared to conventional radio transmission techniques. This is accomplished by the radio changing channels many times per second and each time it changes channels it sends a packet of data. In addition, an increasing number of users can use the same frequency (similar to cellular). Under the regulations, users of FCC certified spread spectrum products do not require a license from the FCC. The only requirement is that the manufacturers of Spread Spectrum products must meet FCC spread spectrum regulations. One of these requirements is that the maximum output power be 4 watts at the antenna. This reduces the range to 25-30 miles with line of site. These rules are designed to drive usage towards local data communications.
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Document ID:
16507CD5
Testing, Maintenance And Operation Of Electronic Flow Computers
Author(s): Gene Herron
Abstract/Introduction:
The electronic flow computer (EFC) is now a major component in the gas measurement process. Contractual agreements generally require greater degrees of gas measurement accuracy and technology continually advances to meet the need. Reliable testing, maintenance and operational methodologies of the equipment are a primary focus for todays field measurement technician.
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Document ID:
9F2AA6A8
Transient Lightning Protection For Electronic Measurement Devices
Author(s): Leon Black
Abstract/Introduction:
We have all heard of or seen the devastating effects of a direct lightning burst. Communication equipment destroyed. Transmitters and EFM devices vaporized into slag metal. Complete process and measurement systems down with extended recovery times. These effects are the most dramatic and the easiest to trace. However, these kinds of events are rare. The more prominent events are those that occur on a day-to-day basis without we, the user, even knowing. With the advent of the transistor and today when surface mount electronics is the norm and not the exception, transient suppression has become a science of necessity. Tight tolerances of voltage requirements and limited current carrying capabilities makes the new compact integrated circuits much more susceptible to many types of transients.
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Document ID:
7D5FFC4E
Calibration Of Liquid Provers
Author(s): Daniel m. Comstock
Abstract/Introduction:
Liquid provers are those provers used to prove meters in liquid service. The purpose of the calibration of a liquid prover is to determine its base volume, in accordance with industry accepted practices, and traceable to recognized standards. Thus the base volume of a prover (BPV) might be determined in accordance with the Manual of Petroleum Measurement Standards (MPMS) of the Amercan Petroleum Institute (API), and be traceable to the National Institute of Standards and Technology (NIST). The base volume of a prover (BPV) is its certified volume at standard conditions (e.g. 60 degrees F and 0 psig in U.S. Customary units, or 15 degrees C and 101.325 kPa in international, SI units).
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Document ID:
6338AA55
Effective Use Of A 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:
C4F0B188
Operational And Field Value Of Flow Calibrating Ultrasonic Gas Meters
Author(s): Garnet Grudeski, Wayne Haner, Jairo Mantilla
Abstract/Introduction:
This paper presents a synopsis of some key considerations to be taken into account when calibrating an ultrasonic meter and describes the on-going operational value that can be provided by the diagnostic information produced by the meter during calibration.
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Document ID:
8886CA07
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:
C34E7E13
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. Two comprehensive reports on the subject have been produced by Park, et al.1 and Gallagher.2 Much of the following information is referred to in detail in these reports.
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Document ID:
A7AEA3AC
Lact Unit Proving ? The Role Of The Witness
Author(s): Art Casias, Terry Ridley
Abstract/Introduction:
Witness, as defined by the New Webster?s 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:
96F6F361
Liquid Meter Proving Techniques
Author(s): J. H. James
Abstract/Introduction:
Producers and shippers are becoming more and more aware of the importance of accurate measurement. Their bottom line depends on it. As a result, measurement accuracy is being scrutinized more vigorously than in the past. Companies are being required to Verify their metering accuracy. Therefore it is essential that all procedures and auxiliary equipment be operated in a defendable manner. In addition, meters are not always in clean product service and could be subject to severe wear. Even meters in clean service will experience wear over time. To ensure meters give accurate results requires regular precision calibration by a prover operated by a competent individual. Meter proving is the means by which meters are calibrated to provide a factor that can be applied to the metered output that will result in a recorded volume that can be traced back to a regulated standard. This is accomplished by passing an identical volume of liquid through both the meter and the prover. The prover is precisely calibrated using regulated standards.
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Document ID:
92059567
Operational Experience With Small Volume Provers
Author(s): Steve Whitman
Abstract/Introduction:
Small Volume Provers (SVPs) were introduced decades ago and are now common technology. There are numerous publications providing empirical data and outlining the technical operation of this equipment. However, the following document will focus on the authors experience, addressing common concerns and questions regarding SVPs.
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Document ID:
50C404ED
Proving Coriolis Meters
Author(s): J. W. Sulton
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 if a pycnometer is used or MPMS Chapter 9, Density Determination if a hydrometer is used. MPMS Chapter 12 Calculation of Petroleum Quantities addresses the calculation of a meter factor and the application of the factor to the flow calculation. The temperature output of a Coriolis meter if obtained from the internal RTD mounted on the sensor tube, is not recommended for use in custody transfer measurement as it is not intended to measure the fluid temperature but the temperature of the tube itself.
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Document ID:
202011BD
Theory And Application Of Pulse Interpolation To Prover Systems
Author(s): David J. Seiler
Abstract/Introduction:
The flow meter has long been established as the industry cash register. With the high cost of producing and the reduced selling price of products, the accuracy of the meter becomes increasingly important to ensure profitability. To this end regular proving of the meter is essential. Liquid meter proving is carried out by placing a Meter Prover in series with the meter under test the prover having a calibrated base volume. Proving of the meter is by comparing the quantity recorded by the meter with the calibrated quantity displaced by the prover.
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Document ID:
C32DC4FA
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:
FE73C073
Witnessing Orifice Meter Calibrations And Field Testing
Author(s): Allen Chandler
Abstract/Introduction:
The need for witnessing gas measurement equipment testing has probably been around since the dawn of the gas custody transfer age. That is, where the gas is physically changing ownership from one entity to another. In the modern age, the old handshake is no longer the equivalent of a valid contract as it once was and rightfully so, each producer, transmission pipeline operator, distribution system owner or transportation broker is concerned that their product is bought and/or sold in as accurate an environment as is humanly possible. Modern day gas prices are volatile to say the least. The market bounces around on an almost daily basis and the price per thousand standard cubic foot of gas seems to steadily increase. Coupled with generally milder temperatures in many regions of the United States and the huge gas volumes that change hands daily, it becomes ever more critical that natural gas is measured with greater accuracy and a witness to the testing procedure is one more positive step toward that end.
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Document ID:
D20C3141
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:
E0B44264
Btu Determination Of Natural Gas Using A Portable Chromatograph
Author(s): Paul Kizer
Abstract/Introduction:
Chromatography is one of the most widely used means of performing chemical analyses in the world. Gas Chromatography has become the preferred method of determining the Btu value of natural gas. The analysis also supplies composition data necessary for gas rate and volume per AGA3, AGA7, AGA 10 and AGA8. (Refs. 1,2,3) Gas Chromatographs are asked to perform in a variety of different environments. The principal types of Chromatographs are laboratory, and At Line.
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Document ID:
A7A32ED2
Chromatograph Applications And Problems From A Users Standpoint
Author(s): Fred Ryel
Abstract/Introduction:
Chromatographs are available for all types of applications in the natural gas industry. The main applications that this class will discuss are: process monitoring of liquids and gases, environmental flares and ambient air, landfill gas and contaminates. These can also include corrosives such as H2S, CO2 and O2, etc. Regardless of the application, the main priority is to capture an accurate sample and not change the properties before it can be analyzed. Maintaining the sample integrity is by far the most difficult process. The procedure of acquiring the sample and the way it is analyzed depends upon the media being sampled.
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Document ID:
AD57A460
Chromatograph Maintenance And Troubleshooting
Author(s): Ronald Sisk
Abstract/Introduction:
Measurement of the quality 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.
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Document ID:
2C0BDB50
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:
D2A06531
Determination Of H2S And Total Sulfur In Natural Gas
Author(s): Ray N. Adcock
Abstract/Introduction:
Hydrogen Sulfide (H2S) is a gas composed of one Sulfur Atom and two Hydrogen Atoms. H2S is formed by the decomposition of organic matter and is therefore, found naturally in crude oil and natural gas deposits. H2S is a highly toxic, transparent, colorless and corrosive gas. Due to the toxic and caustic properties of this gas and its natural presence within natural gas, it is imperative to measure and control the concentration levels of H2S within natural gas pipelines. This paper will discuss the Properties, Purpose of Measurement and Measurement Technologies for H2S and discuss how these technologies can be adapted for measurement of Total Sulfur.
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Document ID:
D69735D7
Determination Of Water Vapor Content In Natural Gas
Author(s): Colin B. Blakemore
Abstract/Introduction:
Manual chilled mirror dewpoint instruments were the first widely used process monitors, and are still used today. The Bureau of Mines Dewpointer is the classic example of this type. The output is the temperature at which liquid dew or frost forms. The operator must distinguish between water and hydrocarbon dewpoints. In the mid-1950s DuPont began manufacturing refrigerants. They needed a moisture analyzer that would measure the water concentration in gases that liquefy at temperatures above that of the water dewpoint. They invented the electrolytic moisture analyzer (P2O5). The output of this instrument is moisture concentration, ppm. The Torry Research Station, Aberdeen, Scotland, developed aluminum oxide moisture sensors also in the mid- 1950s. They were first used to measure the moisture in fish drying ovens. They were first widely used on weather balloons to measure atmospheric humidity. ESSO Research and Development developed the quartz crystal (QCM) based moisture sensor in the mid-1960s. These sensors were first used to measure moisture in the catalytic reformer?s hydrogen recycle gas.
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Document ID:
12C0B6C4
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 The role of each measurement technology is described and assessed in terms of the effectiveness of the measurement method utilised together with other technical considerations as well as initial and operating cost implications. Full consideration is given to the specific difficulties to be confronted resulting from the complex nature of the parameter concerned. Such peculiarities include the effects of pressure, fractional condensation, the minute proportion of heaviest molecular weight components within the gas composition that contributes to the formation of condensate at the hydrocarbon dew point, and the overall subjectivity of the measurement itself where no absolute reference or definition is possible. A case is presented for the use of advanced optical techniques in an adaptation of the fundamental cooled mirror principle to provide automatic on-line measurement with a degree of objectivity and repeatability unobtainable with other measurement techniques.
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Document ID:
C0A3AA9A
Class # 5115.1
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.
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Document ID:
C64E0BCD
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:
757DD64A
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 1930?s, 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 1960?s natural gas was still being flared at the wellhead in Oklahoma. During the 1940?s, 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.
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Document ID:
A36C28D8
Field And Laboratory Testing Of Sediment And Water In Crude Oil
Author(s): Jane Williams
Abstract/Introduction:
The quantity of sediment and water in crude oil must be accurately established as part of the custody transfer process. Purchasers only pay for the crude oil received, and want to minimize the quantity of sediment and water they must dispose of. Consequently, monitoring of the sediment and water content is performed at the production site to prevent excessive sediment and water entering the pipeline system. The quantity of sediment and water a pipeline is willing to accept into their system depends on geographic location, market competitiveness and their ability to handle the sediment and water in the system. Each pipeline publishes the quantity of sediment and water it will accept.
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Document ID:
662055EE
Measurement Of Liquefied Petroleum Gases Lpgs()
Author(s): Brent H. Palmer
Abstract/Introduction:
Liquidified Petroleum Gas (LPG) is defined as butane, propane or other light ends separated from natural gas or crude oil by fractionation or other processes. At atmospheric pressure, LPGs revert to the gaseous state. This paper is intended to provide an overview of metering systems used for the volumetric measurement of LPGs. Operational experiences with measurement systems that degrade the performance of these systems will be addressed. It includes information for turbine and positive displacement meters used in volumetric measurement systems. The basic calculations and industry standards covering volumetric measurement will also be covered.
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Document ID:
89CE7F8B
Additions And Changes To The Latest Revision Of API Chapter 14.1
Author(s): Darin L. George, Eric Kelner
Abstract/Introduction:
Since 1999, the Gas Technology Institute (GTI), the American Petroleum Institute (API), the United States Minerals Management Service (MMS), and Pipeline Research Council International (PRCI) have co-sponsored an extensive natural gas sampling research program at the Metering Research Facility (MRF), located at Southwest Research Institute (SwRI). The results of this research provided a basis for recent revisions to the API Manual of Petroleum Measurement Standards (MPMS) Chapter 14.1, Collecting and Handling of Natural Gas Samples for Custody Transfer. The research supported revisions that produced both the 5th edition of the standard, published in 2001, and the new 6th edition, published in February 2006.
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Document ID:
D2BD9897
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:
2B287DBF
Sample Conditioning And Contaminant Removal For Water Vapor Content Determination In Natural Gas
Author(s): Brad Massey
Abstract/Introduction:
The Natural Gas Industry experiences numerous operational problems associated with high water vapor content in the natural gas stream. As a result several problems are experienced such as, equipment freezes, dilution of physical properties reducing heating value, volume measurement interference, and pipeline corrosion. Contracts and Tariffs usually limit the amount of water vapor content allowed at the custody transfer point. For these and other reasons, accurate Water Vapor Dewpoint measurements are critical measurements for all companies involved in natural gas production, gathering, transmission and delivery. The industry continues to experience problems in obtaining accurate water vapor dewpoint measurements, primarily due to interference problems associated with contaminants and poor sampling techniques. Various types of analytical equipment are being used to determine Water Vapor Dewpoint Measurements. All are susceptible to contaminate interference or poor sampling techniques being utilized. Proper design and utilization of the correct type of sample conditioning devices or improved sampling techniques will provide much more reliable results, regardless of the equipment being utilized.
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Document ID:
2385D53F
Techniques In Gas Composite Sampling
Author(s): Ken Parrott
Abstract/Introduction:
The quality of natural gas in determining overall measurement is a critical component to many applications in our industry. The need to balance plant volumes, measure natural gas within a gathering systems, allocate production to producers in transmission application as well s measurement in custody transfer applications require an accurate analysis of the natural gas flowing in the pipeline. Typically, contracts in custody transfer of natural gas are written to account for the quality of the gas. The quality of the gas is determined by the energy contained in it, which is measured in British Thermal Units or BTUs. A gas chromatograph is typically used to identify individual components of the sample and their quantity, thus determining quality of the sample taken. This chromatographic analysis may take place in a laboratory or in the field. No matter where the analysis takes place, the sample which will be tested must be representative of the flow from which it was taken.
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Document ID:
C9F1622C
Techniques Of Gas Spot Sampling
Author(s): Kris A. Kimmel
Abstract/Introduction:
Since a gas sampling system can be referred to as a cash register it is very important that the correct sampling method be selected and the appropriate industry standard be followed. Methods reviewed by this paper will include spot sampling, composite sampling, and on-line chromatography. In addition, Gas Processors Association (GPA) 2166-86 and American Petroleum Institute (API) 14.1 will be described. Natural gas is sampled to determine quality for custody transfer applications, balance a plant process, or gathering system. In the late 1970s most natural gas custody transfer contracts used gas volume (MCF) for the units of measure. In 1978 Congress passed the Natural Gas Policy Act in an attempt to deregulate the natural gas industry. This act dictated that natural gas should be purchased or sold based on energy content. Today natural gas is purchased based on the amount of energy delivered. The quantity of energy delivered is calculated by multiplying the gas volume per unit time by the energy value (BTU) per unit volume. A gas chromatograph is typically used to identify individual components of the sample and their quantity, thus determining quality of the sample taken. Correctly obtaining, transporting and analyzing the sample is crucial to the accuracy required for custody transfer of this product.
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Document ID:
8C289AF7
Utilizing Equation Of State Eos() Software In Sample Conditioning Of Natural Gas Applications
Author(s): Donald P. Mayeaux
Abstract/Introduction:
Proper sample conditioning is essential to providing a representative sample of natural gas to the analyzer. Sample conditioning consists of extracting a sample from a process stream, transporting it to an analyzer, and conditioning it so that it is compatible with the analyzer. Conditioning generally consists of controlling the gas temperature, pressure, and flow rate. It also includes the removal of contaminates which may alter the sample composition and/or damage the analyzer. It is imperative that the gas sample composition is not altered or distorted during the conditioning process. Equations of State (EOS) software programs are useful tools for modeling the behavior of natural gas as it flows through a sample system. With the use of an EOS program one can determine if conditions in a particular sample conditioning system are conducive to the proper sampling of a specific natural gas composition. EOS software can be useful to the engineer or technician during the design, operation, and maintenance of a natural gas sampling system. This paper will discuss the types of information an EOS program can provide and how this can be utilized to solve common sample conditioning problems.
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Document ID:
A38D6E5F
Moisture Measurement Using Laser Spectroscopy
Author(s): Joseph Mcmenamin
Abstract/Introduction:
Tunable diode laser (TDL) spectroscopy is a mature technology that has been in use for over 20 years. 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 and carbon dioxide in natural gas much faster and more reliably than other methods.
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Document ID:
C160CF02
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:
14C3BADC
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:
AD1F3531
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 company?s corporate image in the 21st Century. Consistent and continuous pipeline operations are key and critical factors in today?s 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:
AE4B5DE2
Selection, Sizing, And Operation Of Control Valves For Gases And Liquids
Author(s): Ken Kleemeier
Abstract/Introduction:
Proper control valve sizing and selection in today?s industrial world is essential to operating at a costeffective 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.
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Document ID:
7F48D98A
Class # 6120
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:
2DCEBB85
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:
4FEE2CA1
Audit Of Electronic Gas Measurement
Author(s): Perry Dee Hummel
Abstract/Introduction:
For years, weve heard that measurement is the cash register of the business. With changes in technology and communications, that cash register is requiring a new approach to perform a measurement audit. New skills, new tools, and human intervention are required to have a good effective auditing program.
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Document ID:
41E3411D
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:
4D1C240E
Overall Measurement Accuracy
Author(s): Ronald E. Beaty
Abstract/Introduction:
This paper presents methods for the determination of the uncertainty that is found in both inferential meters and direct reading meters. Numbers and types of meter, associated variable measured other instrument and instruments used to measure the quality of the natural gas. The effects of the uncertainty can cause a poor system balances.
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Document ID:
4C2754BF
How Sarbanes Oxley Has Affected Gas Measurement In Distribution And Pipeline Systems
Author(s): Ardis Bartle
Abstract/Introduction:
Also known as the Public Accounting Reform and Investor Protection Act, Sarbanes-Oxley(SOX) is a name of the piece of U.S. compliance legislation which was signed off in 2002. Its designed to prevent financial malpractice and accounting scandals such as the Enron debacle. The most relevant , Section 404 of SOX (Management Assessment of Internal Controls) determines the companys internal system of checks and balances. Any public company with stock worth more than 75 million must issue such information in their annual reports. By providing transparency to financial reporting, this overhaul legislation will reduce the string of corporate implosions, earnings restatements and subsequent criminal probes that put thousands of workers out on the street, cost billions of dollars and has led to more than 300 convictions and guilty pleas (according to Justice Department). The Act covers a whole range of governance issues, many covering the types of trades that are allowed within a company, with an emphasis on keeping everything above board. For example, SOX forbids personal loans to officers and directors. Other parts of the Act regulate the responsibilities of the audit committees sent in to check the health of companies compliance.
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Document ID:
D31AF10C
API Mpms Chapter 22.2 - Verification And Testing Protocol For Differential Flow Meters
Author(s): Eric Reid, Russell Burkey, Eric Kelner
Abstract/Introduction:
In 2003, a standard entitled Differential Pressure Flow Measurement Devices, which defined a testing and reporting protocol for flow meters that produce a change in velocity by creating a differential pressure, was developed by the American Petroleum Institute (API) Manual of Petroleum Measurement Standards (MPMS) Chapter 5.7 Working Group. The intent was to provide industry with a standardized testing and reporting procedure that could be used to compare the relative performance of these meters. In 2005, the standard was revised and moved to Chapter 22.2 of the MPMS. In essence, the standard requires the meter to be tested by a qualified test laboratory under various flowing conditions ranging from undisturbed flow (i.e., a fully-developed velocity profile) to severely disturbed (i.e., swirling) flow. The standard also specifies a general report format and requirements for estimating the measurement uncertainty of the test results. The testing protocol is limited to meters used for single-phase Newtonian fluid applications, such as natural gas flows.
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Document ID:
C478A23B
Calibration Using Portable Digital Pressure Indicators
Author(s): Leo J. Buckon
Abstract/Introduction:
The use of electronic pressure calibrators in the gas industry has added new concerns and issues in pressure measurement. Readings appeared that perhaps didnt match the old reliable standby calibration readings or methods, and terms like sensitivity, accuracy, resolution, stability and traceability have become common. Technicians began using correction factors to achieve standard conditions. These correction calculations presented challenges to technicians when performing their calibrations. They began to see the effects of temperature on their test instruments and how temperature affects the accuracy of the gas measurement. More recently, the wide spread use of digital field devices such as smart transmitters has continued to change the technicians world as new tools became necessary to configure and maintain field instrumentation. When using electronic pressure calibration equipment, technicians can make their job easier if they identify and purchase instruments that are traceable, precise, accurate, sensitive, and repeatable. The American Petroleum Institute Chapter 21 gives good advice and recommendations in this area. Communications capability and multifunctionality also help the technician to be more productive in the field.
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Document ID:
96C389A0
Combining Intrinsic Safety With Surge Protection In The Hydrocarbon Industry
Author(s): Donald R. 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 non-incendive 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. The goal of this discussion is to explain just how to achieve both safety and surge protection in hazardous areas using nearly identical engineering techniques.
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Document ID:
20251DCB
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:
4916E33F
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:
863D317D
Class # 8050.1
Author(s): Wade m. Mattar
Abstract/Introduction:
The vortex flowmeter has been used to measure flows of liquids, gases and vapors for several decades. This paper is meant as an overview for anyone new to the technology. Hopefully it will also be a good review for anyone not so new to the technology and will provide some added insight. Some additional reading is also presented with the references. Since the vortex shedding principle is based on the velocity, provided the Reynolds number is sufficient, accurate actual volumetric flow measurements can be made without the need for density compensation. The flowmeter K-factor is independent of the process fluid. A water calibration for example can be used in a gas or steam application. Data is presented which shows the agreement of water calibrations for use in natural gas.
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Document ID:
B4EA5E22
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:
26D71FC3
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:
73156607
Program For Training A Gas Measurement Technician
Author(s): Russel W. Treat
Abstract/Introduction:
Technology in the field of gas measurement and control is constantly evolving. While many are well training in the specific equipment used in their own company?s operation, it is important to have a solid understanding of the fundamentals and theory of operation of the mechanical and physical process involved as well. Therefore, the training of field measurement technicians is of the utmost importance. These technicians must be continually educated in order to possess the most current knowledge of the latest equipment, electronics, communications and metering devices on the market. Also, it is essential that this type of instruction should be taught in a controlled environment where the technicians can learn and develop the necessary skills with the least amount of interruptions from external sources.
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Document ID:
4531E928
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.
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Document ID:
4E25428B
About Ishm 2006
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:
9C7ECAE0