Basics Of High Pressure Measuring And Regulating Station Design
Author(s): E. D. Woomer, Jr.
Abstract/Introduction:
There is more to the design of a measurement facility than the word measurement suggests. Generally, the measurement arena may include any or all of the following: ?? Metering ?? Primary devices ?? Secondary devices ?? Tertiary devices ?? Control ?? Pressure regulation ?? Flow control ?? Overpressure protection ?? Gas Quality ?? Chromatography ?? Spot or composite sampling ?? Analytical instrumentation ?? Other ?? Odorization ?? Filtration / Separation ?? Heating Pneumatic and electronic instrumentation is scattered throughout each of the categories listed above. The detailed design of a measurement facility can become quite involved and exceed the space allotted in this paper. However, the fundamentals will be addressed in regard to the considerations for designing natural gas transmission pipeline measurement facilities. For the purposes of this paper, only metering and regulating (M&R) will be addressed.
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Document ID:
AC3AEE5C
Compressibility Of Natural Gas
Author(s): Jeffrey L. Savidge
Abstract/Introduction:
The accurate measurement of natural gas and natural gas related fluids is difficult. It requires care, experience, and insight to achieve consistently accurate measurements that can meet stringent fiscal requirements. It is particularly difficult to measure complex fluid mixtures that are exposed to: (1) a range of operating conditions, (2) dynamic flow and fluid property behavior, and (3) changing equipment conditions. The compressibility factor is a ubiquitous concept in fluid measurement. It is used throughout many measurement practices and standards. Unfortunately the mathematical methods and data associated with the compressibility factor obscure some of the simple ideas behind it. The purpose of this paper is to provide background on the development of compressibility factor and related methods, discuss their use in natural gas measurement, provide examples of the behavior of the compressibility factor, and illustrate the level of uncertainty that current compressibility factor data, methods and related property standards provide.
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Document ID:
F919462A
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.
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Document ID:
2EEC223E
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 a safe, effective, and economical unit.
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Document ID:
070E9A3A
Determination Of Leakage And Unaccounted For Gas
Author(s): David Wofford
Abstract/Introduction:
Leakage and unaccounted for gas volumes are of the most significant costs of operation for natural gas producers, gatherers, processors, transporters and distribution system operators. These operational costs are so significant that such are directly addressed in tariffs, rate case filings and contractual agreements between parties in order that such may be itemized as a cost of operation, equitably managed and responsibly mitigated. Common acronyms denoting lost and unaccounted for gas volumes are LAUF (Lost And Unaccounted For), LUG (Lost and Unaccounted for Gas) and UAF (UnAccounted For). All of these designations refer to the same issue - Product that you believe you should be able to account for but for some reason cannot. For the sake of this discussion, LAUF shall be our acronym of reference.
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Document ID:
CCD60345
Effects And Control Of Pulsation In Gas Measurement
Author(s): Robert J. Mckee, Ray G. Durke
Abstract/Introduction:
Accurate gas measurement has always been important in the Natural Gas Industry and is even more essential in todays operating environment. Flow meters not only determine how much energy is bought and sold but how much a transportation company is paid for moving gas. One of the most common measurement errors and the most difficult to identify in metering is that caused by pulsating flow. Pulsating flow can be problematic for essentially all types of gas meters. It is important to understand the effects that pulsation has on the common types of flow meters used in the gas industry so that potential error-producing mechanisms can be identified and avoided. It is also essential to understand pulsation control techniques for reducing pulsation effects. This paper describes the effects of pulsation on orifice, turbine, ultrasonic, and other meters used in the industry. It also presents information and suggestions on how to mitigate pulsation effects at meter installations, including a specific procedure for designing acoustic filters that can isolate a flow meter from the source of pulsation.
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Document ID:
064CBC87
Effects Of Abnormal Conditions On Accuracy Of Orifice Measurement
Author(s): Dean Graves
Abstract/Introduction:
Whenever one focuses on gas or fluid measurement, he or she will eventually discover an abnormal condition at a measurement station. Invariably someone will ask, What effect will it have on measurement? A student of measurement may spend years answering this question. This and similar questions have generated many research studies. This research has enabled us to better understand measurement abnormalities and to improve measurement procedures and standards. Even though we have made great strides in measurement, we will continue to ask this question. It is this question that has led to the development of this paper. Instead of focusing on certain specific abnormalities, this paper addresses the overall subject of measurement abnormalities and presents some investigative tools for the reader as they attempt to answer this question. However, before we can understand measurement abnormalities, it is important to review proper or accurate measurement.
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Document ID:
9AD9E596
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:
60A42D74
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:
1B06E61C
Fundamentals Of Gas Measurement III
Author(s): James W. Keating
Abstract/Introduction:
Gas measurement people are concerned with gas laws. To become proficient in all phases of gas measurement, one must fully understand what natural gas is and the theory of its properties. The theories about natural gas properties are the gas laws and their application is essential to natural gas measurement. Quantities of natural gas for custody transfer are stated in terms of standard cubic feet. To arrive at standard cubic feet from actual flowing conditions requires application of correction factors that are defined by the gas laws.
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Document ID:
B7ECB597
Fundamentals Of Gas Turbine Meters
Author(s): Tom Hudson
Abstract/Introduction:
Gas turbine meters were introduced to the U.S. in the 1960s. Since its introduction, the turbine meter has grown in popularity because it has a high degree of accuracy, repeatability, and the ability to cover a large flow range. Gas turbine meters are available with an assortment of configurations, gear driven odometers, ID drives, fully electronic designs with a variety of outputs, and self-correcting models. Many new and imaginative developments have been added to the turbine meter. These greatly improve the utility of the meter and allow it to be used in new flow measurement applications.
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Document ID:
DC8BFCF7
Fundamentals Of Orifice Meter Chart Recorders
Author(s): David Cofer
Abstract/Introduction:
There are two basic components that need to be discussed to understand the fundamentals of orifice meter measurement. One is the Primary Element, which consists of the orifice fitting, orifice plate, meter tube, and other associated components. The other is the Secondary Element, which consists of the equipment used to measure and record the values needed to calculate a volume of gas passing through the Primary Element.
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Document ID:
B4724AA3
Installation And Operation Errors In Gas Measurement
Author(s): Thomas B. Morrow, Edgar B. Bowles, Jr.
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. Next, let the same sensor be used to measure the temperature of natural 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 will occur between the pipe wall and the sensor, and convection heat transfer will occur between the sensor and the flowing gas. In this example, the sensor would not in thermal equilibrium with the flowing gas and the sensor temperature would be different from the flowing gas temperature.
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Document ID:
68012097
Mass Meters For Natural Gas Measurement
Author(s): Karl Stappert
Abstract/Introduction:
Since the early 1980s, Coriolis meters have gained worldwide acceptance in gas, liquid, and slurry applications with an installed base of more than 550,000 units. Through significant design enhancements in the early 1990s Coriolis meters have rapidly gained worldwide acceptance in gas phase applications with over 51,000 meters installed world wide and most notably the 2003 publication of AGA Report Number 11, Measurement of Natural Gas by Coriolis Meter. Having the ability to bidirectionally measure almost any gas phase fluid from -400 to +400 degrees Fahrenheit without concern of error or damage due to flow profile disturbances, pulsations, regulator noise, surges, compressibility change, and density change, Coriolis meters are becoming the fiscally responsible meter of choice in many applications.
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Document ID:
4221D563
Measurement Station Inspection Program And Guide
Author(s): Robert J. Rau
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:
26CDC782
Verifying Gusm Accuracy And Stability Using Advanced Diagnostic Control Limits
Author(s): Martin Schlebach
Abstract/Introduction:
Advancements in the use and understanding of gas ultrasonic meters have been exponential over the last 5-6 years. GUSMs have the ability to provide a vast array of information due to the multiple measurement points and the ability to display flow patterns in three dimensions. These multiple measurements and the corresponding basic diagnostics were initially used to simply ensure that flow, even though distorted in some cases was measured accurately through the full velocity range of the meter. Over time manufacturers and users realized that additional, so called advanced diagnostics were available, these were first discussed by Klaus Zanker at the 2003 NEL SEAsia conference 1. Over time the number of advanced diagnostic values grew to what we currently use today, they include, but are not limited to the following: Profile factor, Symmetry, Cross Flow, Turbulence, ETA and Swirl angle. These values coupled with the original basic diagnostic values help ensure that both the meters performance and the assemblies dynamics remain constant. The nagging question has been how do I know if the meter and the system dynamics are within a range that ensures confidence in the meters operation and the systems accuracy, this will be discussed in the following pages. A basic understanding of ultrasonic meter operation and geometry is a prerequisite to fully understanding this topic, some basic information can be found in appendix A.
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Document ID:
F05FDCCE
Orifice Fittings And Meter Tubes
Author(s): Darren Schwarz
Abstract/Introduction:
The desire for accurate measurement of flowing fluids and methods used to achieve that objective date back many, many centuries to ancient Roman and Chinese civilizations. Equipment and methodology developed over time has brought us a variety of measurement devices with specific capabilities to cover a wide range of fluid flow measurement needs. In many modern applications, the differential or head meter is still the device of choice. Differential meters commonly exist today in the form of venturi, flow nozzle and flat plate orifice meters. For comparison, a brief overview of venturis and flow nozzles will be presented but for the purposes of this presentation our attention is directed primarily to orifice meters and the configurations commonly used today. Regardless of the type, in the overall metering system these devices are typically referred to as the primary element.
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Document ID:
41431F56
Orifice Meter Maintenance And Operation
Author(s): Scott Smith
Abstract/Introduction:
The natural gas industry has seen many changes lately. The world population is increasing and with this the energy demands in the world are also increasing. Producers and pipeline companies have seen tremendous growth and reorganization through these increased demands for energy. The advances in technology in the last decade have put a computer and cellular phone at everyones fingertips literally and increased the need for electricity, thus the need for natural gas to generate this electricity. With this increased demand for natural gas, the logistics involved in acquiring it, and the profit differential between these two, the need for proper maintenance is more important than ever.
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Document ID:
8431ABCA
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:
7885627D
Thermometry In Gas Measurement
Author(s): Stephen T. Stark
Abstract/Introduction:
The measurement of gas temperature is not easy. In fact, gas temperature is one of the more difficult variables to measure correctly. Temperature plays an important role in gas flow calculations where ultrasonic meters, orifice meters, turbine meters, diaphragm meters, displacement-type meters, and many other meter types are used.1,2,4 Measured several times between the wellhead and its final point of consumption, natural gas temperature is ever changing. When gas molecules are packed tightly together, such as when flowing through a gas compressor, they heat up. When gas expands after flowing through a regulator or other restriction, it cools down. Natural gas temperature is also affected by the temperature of the pipe through which it flows. The measurement of gas temperature contributes directly to overall measurement accuracy. The greater the temperature measurement error, the higher the overall measurement uncertainty becomes. Even relatively small temperature measurement errors can have a large impact on the bottom line.
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Document ID:
F1A8523F
Wet Gas Measurement
Author(s): Philip A. Lawrence
Abstract/Introduction:
Wet gas measurement is becoming more prevalent in the modern oil and gas market place. The effect of entrained liquid in gas and its impact on measurement systems is being researched world wide by various laboratories and JIP working groups. The impact can be very significant financially. The subject is quite large and encompasses many different concepts, meter types and opinions, with many new ideas being brought to the forefront each year as more research is done. This paper will discuss and describe the phenomenon of wet gas and some of the various types of meters that are and may be used for this type of measurement, together with some recent thinking and concepts associated with wet gas measurement, The writer will mention some of the terms and mathematical concepts used to enable the reader to grasp a better understanding of what this stuff is about!
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Document ID:
6DD2BFF0
Flow Conditioners For Natural Gas Measurement
Author(s): James E. Gallagher
Abstract/Introduction:
The full cost of ownership consists of the initial capital, commissioning, training, spare parts, maintenance and calibration costs for the lifetime of the equipment. The full cost is several times the initial capital investment and should be the deciding factor in equipment selection. The technical selection - accuracy, repeatability, drift, ease of calibration as well as reliability indirectly affects the cost of ownership. Proper installation and application of flowmeters are two of the most significant parameters in the measurement chain. These parameters influence the factors mentioned above and are neglected in most assessments. The misapplication of any device brings the wrath of field personnel on the operating companys engineering staff, as it should! More effort is required by the user community to match their expectations with reality. The selection, installation, operation and maintenance of quality equipment, if properly performed, are almost never discussed by operating personnel.
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Document ID:
6EE46443
Application Of Densitometers To Liquid Measurement
Author(s): Ray N. Adcock
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:
32FD051A
Application Of Turbine Meters In Liquid Measurement
Author(s): Dave Seiler
Abstract/Introduction:
Liquid turbine meter design has changed little from the original Potter design developed in the 1960s. Although originally designed for low - accuracy water flow measurement, its application into the aerospace industry called for higher accuracy and reliability as well as simplicity in design. At the same time petroleum and petrochemical industries adopted the meter. With the publication of API 2534 in March 1970, the liquid turbine meter became a recognized meter for use in custody transfer of refined products and pipeline systems as well as tanker and barge loading or unloading of crude oil.
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Document ID:
A8515B7D
Calculation Of Liquid Petroleum Quantities
Author(s): Peter W Kosewicz
Abstract/Introduction:
In the Petroleum industry as hydrocarbons are purchased, sold or transferred there are two key elements that must be determined. These elements are the quantity and quality of the hydrocarbon in question. This paper will address one of those elements, the determination of the quantity of the hydrocarbon in the transaction. The determination of the quantity of hydrocarbon can be further subdivided into: Static quantity determination and Dynamic quantity determination Static quantity is determined when the hydrocarbon is measured under non-flowing conditions, such as when contained in a tank, rail car, truck or vessel. Conversely Dynamic quantity determination occurs when the hydrocarbon is measured under flowing conditions.
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Document ID:
BC397668
Calibration Of Storage Tanks
Author(s): Dan Comstock
Abstract/Introduction:
This paper will give an overview description of different methodologies and technologies for the calibration of above ground upright cylindrical steel tanks. Brief descriptions will be given on several methods including the referee manual strapping method (MTSM), a couple of optical methods and an internal electro-optical method. Tank calibration by dimensional measurements is often referred to as tank strapping whether the manual strapping or optical methods are being used. Tanks in this paper include cone roof tanks, external floating roof tanks, internal floating roof tanks and insulated tanks. All discussions will be in the context of current API and ISO standards.
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Document ID:
00176383
Crude Oil Blending
Author(s): Kevin B. Macdougall
Abstract/Introduction:
There are a number of applications that require blending of crude oil or other hydrocarbons and they include transportation needs, pipeline capacity, product value and refining efficiency. Crude oil blending is accomplished by two methods: on-line blending and tank blending. On-line Blending In this method two or more components are injected from separate pipelines and are mixed in a single line. Ensuring adequate mixing is a necessity and often requires some type of in-line static mixer or mechanical mixing device. The use of piping elements alone may not provide adequate mixing. The efficiency of this method will depend upon the resulting streams Reynolds number, the type and number of piping elements, and the time allowed for mixing. With either method, the use of an injection quill for the smaller of the two streams will assist in mixing.
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Document ID:
E3094FA4
Crude Oil Gathering By Truck Metering Versus Manual Gauging
Author(s): J. W. Sulton
Abstract/Introduction:
Normal procedures for custody transfer of oil from lease tanks requires the driver/gauger to manually gauge the producers storage tank to determine the volume of oil in the tank and the S&W content of the oil. This procedure requires the driver to climb to the top of the tank where exposure to H2S or injury from falling from the tank is a risk. This paper will compare the manual method of tank gauging as described in API Chapter 18, Section 1 to the use of a measurement system that is mounted on the transport truck. The truck mounted measurement system relates to a system and a method for measuring crude oil, and more particularly to a system for accurately measuring oil as it is transferred from a lease storage tank to a transport vessel.
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Document ID:
F8DB1480
Design, Operation And Maintenance Of Lact Units Class # 2090.1
Author(s): Miles Chaney
Abstract/Introduction:
The intent of this class is to give un-biased guidance to the design, operation and maintenance of Lease Automatic Custody Transfer units. A L.A.C.T. is an arrangement of equipment designed for the unattended custody transfer of liquid hydrocarbons from producing leases to the transporting carrier. An A.C.T. would be a truck or meter station where the transfer of liquid hydrocarbons takes place away from the producing lease itself. For the purpose of this class both will be referred to as L.A.C.T. units.
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Document ID:
2D49C40F
Displacement Meters For Liquid Measurement
Author(s): Tom Piskorski
Abstract/Introduction:
The petroleum measurement industry continues to demand a liquid flow meter that has a high degree of repeatability, linearity, and stability. Meter repeatability is the ability of the meter to reproduce the same meter factor, given the same conditions. Linearity is the ability of the meter to have a meter factor within a specified percentage deviation from maximum flow in comparison to minimum flow. Stability is the meters ability to reproduce the same meter factor time after time for some given length of time, given that the operating conditions are the same.
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Document ID:
DB9BD36A
Effects Of Flow Conditioning On Liquid Measurement
Author(s): James E. Gallagher
Abstract/Introduction:
The full cost of ownership consists of the initial capital, commissioning, training, spare parts, maintenance and calibration costs for the lifetime of the equipment. The full cost is several times the initial capital investment and should be the deciding factor in equipment selection. The technical selection - accuracy, repeatability, drift, ease of calibration as well as reliability indirectly affects the cost of ownership. Proper installation and application of flowmeters are two of the most significant parameters in the measurement chain. These parameters influence the factors mentioned above and are neglected in most assessments. The misapplication of any device brings the wrath of field personnel on the operating companys engineering staff, as it should! More effort is required by the user community to match their expectations with reality. The selection, installation, operation and maintenance of quality equipment, if properly performed, are almost never discussed by operating personnel. The role of flow conditioning is to ensure that the real world environment closely resembles the laboratory environment for proper performance of inferential flowmeters
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Document ID:
1FA78F29
Effects Of Petroleum Properties On Pipeline Measurement
Author(s): Jim Smith
Abstract/Introduction:
Measurement of liquid hydrocarbons in most pipelines today is done on a standard volume basis or by mass. These measurement points typically are custody transfer and are the cash register measurements between the two parties involved in the transactions. This is one reason why the measurement accuracy is critical with another being product accountability. The volume or mass measurements must account for the entire liquid product received or delivered in order to track and determine if product is being lost or gained. Several fluid properties can change the accuracy of this measurement and knowing how they impact the measurement is crucial to its integrity. This paper will focus on dynamic measurement or measurement by metering and discuss several fluid properties and their affects on measured results involving the common types of metering technologies used today.
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Document ID:
CBA9E7FA
Phase Measurement Of Dense Phase Fluids
Author(s): Ron Labus
Abstract/Introduction:
Dense phase measurement refers specifically to fluid measurement, of what is ostensibly a liquid regime, but due to the operating conditions encountered exhibits properties of both liquid and gas states. Most significant of these anomalies are increased compressibility and density values that are akin to a liquid while being neither a liquid or a gas a single phase plasma absent void fraction. From a mass measurement view point, this can result in a loss of correlation to published density tables for NGLs and a reliance on empirically derived tables for Ethylene. Historically this class has emphasized the difficulties encountered in the measurement of polymer grade ethylene. Ethylene is typically measured in dense phase a fluid regime encountered when a liquid enters the arena of critical pressure and temperature and becomes fluid plasma. Under these conditions it is neither gas nor liquid, but a plasma or dense phase material. Ethylene is not alone in terms of difficult liquid measurement made in dense phase regimes. The potential errors that result can produce serious problems for the unwary. While empirically derived tables have served the industry well in the case of ethylene, a better correlation may be possible for critical NGL measurement.
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Document ID:
6D0F5B34
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:
8FBF4711
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:
06CA8C5F
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:
50DC0BE1
Fundamentals Of Liquid Turbine Meters
Author(s): Dave Seiler
Abstract/Introduction:
Liquid turbine meter design has changed little from the original Potter design developed in the 1960s. Although originally designed for low - accuracy water flow measurement, its application into the aerospace industry called for higher accuracy and reliability as well as simplicity in design. At the same time petroleum and petrochemical industries adopted the meter. With the publication of API 2534 in March 1970, the liquid turbine meter became a recognized meter for use in custody transfer of refined products and pipeline systems as well as tanker and barge loading or unloading of crude oil.
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Document ID:
63292D99
Gauging, Testing And Running Of Lease Tanks
Author(s): Jane Williams
Abstract/Introduction:
Many production sites do not have metering facilities for custody transfer. Metering facilities require additional capital expenditures but minimize the labor costs over the life of the lease. If metering is not available at the field location the custody transfer measurement is generally performed by manual tank gauging. In this case, after gauging the tank can be emptied into a truck or into a pipeline. Another method which is used occasionally is to have a meter on the truck which serves as the custody transfer. However, the majority of locations which do not have a LACT (Lease Automatic Custody Transfer) Unit utilize the tank gauge as the means of custody transfer. The procedure for gauging of tanks is covered by API (American Petroleum Institute) MPMS (Manual of Petroleum Measurement Standards) Chapter 3. Verification of the equipment utilized in the gauging process against certified test standards which are traceable to the NIST is now required.
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Document ID:
8D65BAC6
Helical Turbine Meters For Liquid Measurement
Author(s): Ishm Class 2202.1
Abstract/Introduction:
In this class we will review the theory, operation and characteristics of the helical turbine meter and why it performs so well in difficult applications. The Helical Rotor turbine flow meter is an outgrowth of the flat bladed turbine that has been in service for many years, and offers significant performance advantages. These advantages are seen in crude oils, multi-viscosity and other problematic flow measurement applications. Helical turbines have been used in crude services up to 500 cSt in standard applications and over 800 cSt in special applications. In the area of multi-viscosity applications helicals operate over very wide ranges. Helical turbine meters will operate at specification over viscosities from 0.6 to 160 cSt and above with a single meter factor.
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Document ID:
ADAA1888
Installation And Operation Of Densitometers
Author(s): Don Sextro
Abstract/Introduction:
A densitometer is an on-line and continuous device used to measure the density of a flowing stream. In the oil and gas industry, a densitometer is normally used to measure the density of liquid hydrocarbon finished products like propane and gasoline and liquid mixtures like Y-grade natural gas liquids (NGL), but can also be used to measure the density of crude oil. The typical installation is in a single-phase liquid stream, but densitometers can be used to measure single-phase gas or vapor. This paper addresses only continuous, on-line liquid density measurement.
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Document ID:
5280CD7B
Liquid Measurement Field Surveys
Author(s): Christopher Levy
Abstract/Introduction:
Liquid measurement tasks must be performed consistently according to a specific rulebook, or set of equipment design specifications and operational processes and procedures, in order to achieve acceptable system performance. A company may choose to simply utilize the API Manual of Petroleum Measurement Standards as its measurement rulebook or to maintain its own internal set of governing measurement documents specific to its technical and business needs. For both design specifications and operating processes and procedures, a significant amount of effort is required to ensure measurement documents are kept current with respect to equipment advances and potentially changing operating criteria. Establishing and maintaining this measurement rulebook, however, must be accompanied by continued training and by an assurance program that ensures equipment is operated and measurement tasks are performed as intended. Assurance programs provide a feedback loop that measures the success of the implemented measurement program so that adjustments can be made to address deficiencies and achieve desired results.
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Document ID:
187B4E09
Liquid Measurement Station Design
Author(s): Kevin J. Tansey
Abstract/Introduction:
Liquid Measurement Stations are necessitated by agreements between petroleum buyers, sellers, and transporters along with appropriate customs and or governmental authorities. These agreements outline how the fluid is to be measured and how the results will be traceable to recognized standards. In the case of common carrier pipelines, the pipeline is entrusted with the transport of their customers fluid, thus loss control by use of accurate liquid measurement stations is essential. It is important to note that everyone involved has an interest in the true net volume or associated mass. In addition to meeting the requirements for measurement, stations must meet numerous safety and construction codes and standards, as the fluids are normally hazardous. Operation of the measurement station must be relatively simple and a user-friendly operator interface is highly desirable. The task of the station or system designer is to transform these requirements into engineering specifications, drawings, and bills of materials, for procurement, manufacture, test, certification, and delivery to the end user of a cadre of components specifically selected and assembled to work together to meet the requirements of the measurement agreement and applicable codes. This paper will discuss the various topics the designer must address and the methodology he must use to produce a satisfactory system.
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Document ID:
35E75A20
Marine Crude Oil Terminal Measurement Systems
Author(s): Harold E. Osborn
Abstract/Introduction:
Crude oil terminals are very important to our industry. We now import more than 50% of the raw material from which we make our gasoline, crude oil. This means that we must import several million barrels of crude oil per day. Since we have no pipelines running across the ocean floors of our planet, we have to transport that crude oil on marine vessels. This means that we have to be able to load and unload large vessels quickly and with a high degree of accuracy
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Document ID:
36272A5F
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:
8C98722A
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:
F73E95A9
Measurement Accuracy And Sources Of Error In Tank Gauging
Author(s): C. Stewart Ash, P.E.
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:
112385BA
Shrinkage Losses Resulting From Liquid Hydrocarbon Blending
Author(s): J. H. Harry() 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:
1C5ADF95
Measurement Of Cryogenic LNG
Author(s): Dr Gregor Brown
Abstract/Introduction:
With depletion of conventional oil reserves, natural gas is becoming an increasingly important source of energy for many countries, including the USA. While some of the demand for natural gas can be met by domestic production or pipeline imports, many countries are becoming increasingly dependent on natural gas imports in the form of LNG. One county which is very a potent example of the importance of LNG, is Japan, which currently imports about 97% of its gas in the form of LNG. LNG imports to Japan represent the majority of global trade in the product and are supplied mainly from Indonesia and Malaysia, the worlds top two LNG exporters. Figure 1 below shows the forecast world trade in LNG for 2015, with the majority LNG being imported by the USA and the Asia Pacific region.
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Document ID:
B4C91DE3
Measurement Methods For Liquid Storage Tanks
Author(s): Robert Arias
Abstract/Introduction:
This paper will provide, in general terms, an overview of the different technologies available to measure Net Standard Volumes in storage tanks. The Net Standard Volume (NSV) is used as the primary unit of measurement for custody transfer and/or Inventory Control. The Net Standard Volume (NSV) documents the agreement between the representatives of the interested parties (custody transfer) of the measured quantities and qualities of the transferred liquid.
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Document ID:
5440C4D1
Measurement Of Petroleum On Board Marine Vessels
Author(s): John A. Jack 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. It must be recognized at the beginning of this discussion that marine vessels ARE NOT designed or built to be accurate measurement facilities. It has been said that measurement of bulk liquids is an art and not a science. This is truly applicable to measurement of petroleum on board marine vessels.
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Document ID:
6E0C0280
Resolving Liquid Measurement Differences
Author(s): Herbert H. Garland
Abstract/Introduction:
What is a custody transfer? It is the volume of liquid moved multiplied by the tariff, which equates to ! It is the bottom line, which is the cash register. Is your companys cash register running over or short? What is the percentage it is off? To minimize liquid measurement problems, clear lines AUTHORITY and RESPONSIBILITY must be established and accepted. Established by management and accepted by the employee(s) assigned this role. To adequately perform loss/gain tracking and analysis you must be able to RECOGNIZE that a problem exists. More often than not we tend to think it is the other person or company that has the problem. It is a matter of admitting you may have the problem instead of the others. Check your equipment and procedures first. DETERMINE what is causing the problem. Is it an error in procedure, equipment failure, malfunction or a calibration problem? Or is it human error? When this has been determined, you can then CORRECT the problem.
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Document ID:
D84D0A36
Statistical Control Of Meter Factors - A Simplified Approach
Author(s): Dan Comstock
Abstract/Introduction:
This paper will give a brief overview description of a simplified method for monitoring the performance of a flow meter and performing the same exercise on each meter in the system. The idea is to provide graphical assistance, through the use of meter factor control charts in: (a) developing preventive maintenance programs (b) heightening awareness of alarm situations, and (c) reducing risk to the financial bottom line. Meter factor control charts and logs make it easier to prepare reports to maintenance, operations, financial and executive managers from time to time and furthermore, they make it easier for the target audience to digest the points being made.
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Document ID:
2EA3150D
Troubleshooting Liquid Pipeline Losses And Gain
Author(s): Joseph T. Rasmussen
Abstract/Introduction:
Todays pipelines are multi-dimensional systems providing multiple services for many shippers and customers. Pipeline systems may connect multiple origins and destinations, and carry various products across long distances with changing profiles, pipe dimensions and directions. Monitoring pipeline losses and gains employs tools and analysis methods developed specifically to troubleshoot pipeline variances. Examination of pipeline losses and gains uses basic statistical tools as well as intuitive and creative insight into what controls losses and gains. The basic tool for evaluating system performance is Loss/Gain, a measure of how well receipts, deliveries and inventory match up over a period of time. The concept is similar to that used for leak detection, but usually covers a longer time period. Loss/gain is a measure of the quality of the overall measurement in a system, and excessive loss/gain can signal the need for an investigation to identify causes and develop corrective actions. Good measurement can be enhanced by continuously monitoring the system, equipment and procedures to insure they are operating within acceptable limits. This monitoring may be accomplished by the use of Control Charts. This paper will review control charts and procedures, which may be used to monitor systems, and offers troubleshooting guides to use when a pipeline systems loss/gain is out of tolerance.
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Document ID:
934C58BE
Ultrasonic Meters For Liquid Measurement
Author(s): Sid Douglass
Abstract/Introduction:
Gas and Oil are different in their physical, chemical, and ultrasonic properties. Nevertheless, each fluid state can use WideBeam technology that uses the pipe wall as a Sonic Waveguide, permitting accurate, repeatable and reliable non-intrusive flow metering. This paper explains non intrusive Liquid and Gas ultrasonic metering, providing field and laboratory test data demonstrating the ability of WideBeam Clamp-On Ultrasonic flow meters to provide highly accurate Check Metering.
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Document ID:
4FA4F549
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:
B71DED21
Measuring High Viscosity Liquids With Flow Meters
Author(s): Raymond J. Kalivoda
Abstract/Introduction:
There has been a continuous increase in the demand of heavy crude oil due to the price and availability. This trend is expected to accelerate with increasing demand for petroleum products due to the expansion of the world economies and the reduction in light low viscosity crude oil reserves. As a result of this trend crude oil transporters, pipeline and marine, are gearing up to handle a wider range of heavy crude oils.
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Document ID:
9CEA84B6
Proving Liquid Meters With Microprocessor Based Pulse Outputs
Author(s): Galen Cotton
Abstract/Introduction:
The advent of microprocessor driven flow meters in the late 1960s and early 1970s was heralded as a new frontier in flow measurement. Little did we anticipate the unintended consequence of adopting these new technologies or how our conventional verification techniques would be challenged by them. We are still playing catch-up in the realm of flow meter verification where manufactured or, computationally derived flow meter pulse outputs are concerned.
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Document ID:
75C60035
Proving Liquid Ultrasonic Meters
Author(s): Galen Cotton
Abstract/Introduction:
Precision (multi-path) Ultrasonic transit-time flow meter technology (UFM) has been around for over 50 years and while widely used in the measurement of water, particularly in nuclear feed water applications and some notable military applications, it did not begin to make serious inroads in the petroleum industry until the beginnings of this decade. It owes much of its current success to those with sufficient vision and determination to author standards, participate in development verification trials, and, ultimately, deploy the technology in the face of substantial challenges to field verification of performance.
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Document ID:
BC8B9CFF
Accuracy Diagnostics Of Liquid Ultrasonic Flow Meters
Author(s): Joshua W. Rose
Abstract/Introduction:
Liquid ultrasonic flow meters are not new to the measurement of crude oil, but over the last decade technology improvements have enabled liquid ultrasonic meters to meet the higher accuracy requirements needed for custody transfer measurement. The transit time principle of measurement has opened a window to allow observation and measurement of aspects of the flow stream that have never been visible to traditional measurement technologies such as PD meters and turbine meters but are critical to the proper operation of a liquid ultrasonic meter. This paper will discuss the specific diagnostic capabilities of the FMC Ultra6 liquid ultrasonic flow meter and how this information can contribute to maintaining high accuracy custody transfer measurement.
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Document ID:
456512A1
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:
F34A5F18
Offshore Liquid Fpso Measurement Systems
Author(s): T. Cousins
Abstract/Introduction:
Floating production, storage, and offloading systems (FPSOs) receive crude oil from deepwater wells and store it in their hull tanks until the crude can be pumped into shuttle tankers or oceangoing barges for transport to shore. They may also process the oil and in some later FPSOs to be used for Gas distribution. Floating productions systems have been utilized in remote offshore areas without a pipeline infrastructure for many years. However, they have become even more important with the push by the offshore industry into ever deeper waters. Floating production, storage, and offloading/floating storage and offloading (FPSO/FSO) systems have now become one of most commercially viable concepts for remote or deep-water oilfield developments. They also allow a company to develop offshore resources quickly between discovery and production. They have been shown to reduce this time as much as two to four years. Further there can be significant cost savings in developing marginal fields.
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Document ID:
8171179D
Applications In Liquid Measurement Using Clamp-On Ultrasonic Technology
Author(s): C. Tim Guest
Abstract/Introduction:
Clamp-On ultrasonic flow meters (UFMs) have been in use by various industries for flow measurement for about three decades. When Clamp-On UFMs were first introduced to the industrial market in the mid 1980s, they were primarily applied in the Water & Waste Water Industry. In those early days Clamp-On UFMs primarily used Doppler technology, whereas modern Clamp-On UFMs predominately utilize Transit Time technology. As the accuracy, repeatability, and reliability of these meters improved over the years, the acceptance of Clamp-On UFMs in the Oil & Gas Industry has grown. Today Clamp-On UFMs are becoming widely used in a variety of critical non-custody applications in the Oil & Gas, Hydrocarbon Processing, Chemical Processing and other industries.
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Document ID:
F56BD6B9
Advanced Application Of Flow Computers And Telemetering Systems
Author(s): Shawn Kriger
Abstract/Introduction:
The dividing line between electronic flow computers (EFM), remote terminal units (RTU) and programmable logic controllers (PLC) has become clouded. Back in the 1980s, when flow computers were first introduced into our industry, many companies would use each of these technologies to fit a specific application. Flow computers were used to measure gas volumes. RTUs were used for monitoring additional temperatures and pressures and to perform control applications. PLCs were mainly used for custom applications, mostly associated with processing plants. This often lead to complex systems with many different device types, communication networks and host systems which can be difficult to manage. The rapid advancement in software and hardware technology has created a new generation of flow computer with hybrid functionality.
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Document ID:
CDE0C213
Application Of Flow Computers For Gas Measurement And Control
Author(s): Jerry Van Staalduine
Abstract/Introduction:
Electronic flow computers (EFCs) are rapidly becoming the standard for real-time gas measurement. As these devices become more and more capable, advanced control strategies are becoming commonplace. As more and more EFCs are commissioned, customers 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 device 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:
084179AF
Applications Of Portable Computers And Software
Author(s): Trey Thee, B.J. Walker
Abstract/Introduction:
The natural gas industry has undergone substantial changes over the last few decades. One of the largest changes has been in the way data is collected and stored. Laptops and PDAs are the most prevalent methods of data collection and storage in the field today. The use of these tools led to great leaps in productivity but in order for similar productivity increases to happen in the future and to maintain gains of the past, hardware and software must be chosen carefully. In this paper we will discuss mobile computing in the Natural Gas Industry.
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Document ID:
6D464256
Basic Applications Of Telemetering Systems
Author(s): Tommy Mitchell
Abstract/Introduction:
In a fast changing natural gas industry today it is important for companies to utilize all available technologies in order to safely operate and maintain a competitive edge in todays market place. One of many available technologies is telemetering. To understand telemetering let us first give a good definition of telemetering and how it applies to todays natural gas industry. Telemetering is defined as: The science of sensing and measuring information at a remote location and transmitting that data to a convenient location to be read and recorded. From this definition we can see that telemetering, as it applies to the natural gas industry, is simply a way to gather, read and record data remotely so it can be utilized. Some of the most common reasons companies install a basic telemetering system today are safety, increase production, improve operations efficiency, and monitor pipelines. However with todays advanced Flow Computers and RTU designs the reasons listed above can be easily achieved in most cases by installing one unit per location. It is the intent of this paper to cover basic telemetering principles as they apply to areas of the Oil and Gas Industry.
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Document ID:
75FAA5BD
Basic Electronics For Field Measurement
Author(s): Dale Gary
Abstract/Introduction:
The three basic laws we will discuss are Ohms law, Kirchhoffs voltage law, and Kirchhoffs current law. The main terms used are voltage (units are Volts), current (units are Amps or milliamps), and resistance (units are ohms). These terms by themselves are meaningless unless a relationship can be established. An analogy that we can use to visualize the relationship between voltage, current and resistance is water flowing through a pipe. In the water analogy, pressure that pushes the water would correspond to voltage. The water flowing through the pipe would correspond to current. Any obstruction in the pipe restricting the flow would correspond to resistance.
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Document ID:
6D4E4803
Scada Systems
Author(s): Ed Smyth
Abstract/Introduction:
SCADA systems provide for safe, reliable, semi-efficient operation of oil and gas systems. Advanced applications and interfaces to business systems provide the keys for highly profitable operation. This paper introduces the basic building blocks of the SCADA system, including field devices. The SCADA host and advanced applications are discussed in detail. The paper concludes with a discussion of SCADA trends.
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Document ID:
147CE665
Communication Systems For Gas Measurement Data
Author(s): Ben Hamilton
Abstract/Introduction:
This is a rewrite of my 2006 ISHM paper it contains revisions and additional content. 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 on 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 our needs. In fact complex systems usually rely on numerous connectivity methods. Some of the options are described here.
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Document ID:
F12E37EB
Economics Of Electronic Gas Measurement
Author(s): Jason Orf
Abstract/Introduction:
Electronic Gas Meters (EGMs) have several different tangible and intangible benefits for each phase of our industry. The tangible costs are very similar from business to business but the intangibles vary. Producers have a much more complex justification process since it is related to well efficiency, labor costs, and benefits of real-time rates and must clearly justify the use of EGMs. We will first discuss the meters differing accuracy of both chart recorders and EGMs. There are advantages and disadvantages to both, so a clear understanding of these should come into play in the justification. Then the costs of both will be compared using different assumptions, including the use of automation equipment. Finally we will try to summarize what key points should be used in the justification of EGM measurement.
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Document ID:
132190AD
Production Equipment Effects On Gas Measurement
Author(s): David Pulley
Abstract/Introduction:
American Gas Association states that measurement of natural gas by an orifice meter requires a single phase hydrocarbon through the metering area which allows an accurate measurement of differential pressure across the orifice plate, flowing temperature, and component analysis at a metering station. Some gas contracts state that the producer shall condition the gas for metering which would allow accurate measurement of gas flowing through the metering station. To meet the AGA and Contract requirements personnel need to have a knowledge and operational understanding of production equipment used to condition gas prior to the point of measurement. To achieve this condition field personnel should have an operational understanding of production equipment by which they can perform maintenance on and make adjustments to achieving an optimum flowing condition within the metering tube.
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Document ID:
DA0012C3
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:
F7C645E2
Ethernet In Scada Systems
Author(s): David Crandall
Abstract/Introduction:
The explosive demand for information within enterprises has driven the control of SCADA systems networks beyond the exclusive domain of the SCADA department. Ethernet enables todays SCADA systems to provide real time data directly to the SCADA, Measurement, and Accounting groups which raises the need for additional security, industry standardization via OPC, and IT department involvement. The significance of these changes compared to past operating methods is that Measurement and Accounting now have access to real-time data with standard off the shelf software packages. This is accomplished from the same network the SCADA system utilizes to obtain its data. Disparate bits of data that required days and weeks to collect before being analyzed are now available instantly via Internet Explorer web browsers. The security of this data is of extreme importance and now the IT department demands the same or higher levels of security for the field as they do the front office. This means security measures must be enhanced within field devices going forward. One vendor has addressed security of its field device and added unique security features into its Ethernet port. Modern SCADA systems are based on an architecture that utilizes Ethernet communications permitting significant improvements in data availability which is driving the major operational gains in overall system performance.
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Document ID:
61013A6D
On-Line Computers For Custody Transfer
Author(s): Mark Godfrey
Abstract/Introduction:
Flow Computer is the term often associated with the use of on-line computers used for the determination of the quantity transferred between two parties in a hydrocarbon custody transfer measurement system. A flow computer is typically a specialized hardware platform running a single, dedicated program often referred to as the flow computer firmware that in combination, receive inputs from flow meters and associated transmitters (Pressure, Temperature, Density, etc) calculates flow rates and flow totals and then outputs these values. The embedded calculations would be in accordance to industry standards such as those published by organization such as API, AGA, ISO, GPA etc. The flow computers output can be anything from a simple displayed value, through analog or pulse values, printed reports, to direct communication of data to other computers and computer systems.
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Document ID:
C4268B4D
Real Time Electronic Gas Measurement
Author(s): Jim Griffeth
Abstract/Introduction:
For many years now, flow computers have been implemented in gas measurement systems to utilize technology, to improve measurement accuracy, provide far more efficient data acquisition, and provide better control resources for remote interface through telemetry. As the meters functionality has increased, the meter technician has had to become more diverse in his or her knowledge of measurement, control, computers, and electronics. By taking a closer look at the various advanced applications and reviewing the basics, hopefully the technician will have a better understanding of the requirements of handling, installing, and working with todays advanced flow computers.
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Document ID:
41B67134
Spread Spectrum Systems For Efm And Scada
Author(s): Jim Gardner
Abstract/Introduction:
As oil and gas companies work toward greater automation and e-business solutions, the challenges of getting real-time, reliable data from remote locations continues to be one of the greatest hurdles. Today, there are many fine choices in electronic flow measurement (EFM) and remote terminal unit (RTU) equipment available. There also are many fine bug free software programs to archive, audit, and display the collected data. The single biggest problem remains communications. It is a commonly held belief that over 80 percent of all SCADA system problems are communication failures.
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Document ID:
08D1379F
Smart Transmitter Selection, Calibration And Installation
Author(s): Leon Black
Abstract/Introduction:
In 1985, while working on aeronautical transmitters at Honeywell Industries, Mr. Paul DuPuis described the definition of future transmitters. It has taken the industry 20 years plus to catch up with his forward thinking approach While researching the background for this paper, it became clearly evident that every manufacture in the industry has a different definition of SMART transmitter. Even the standards groups, IEEE, ANSI/ISA and others cannot agree on what constitutes a SMART transmitter.
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Document ID:
0FEA542E
Testing, Maintenance, And Operation Of Electronic Flow Computers For The Gas Industry
Author(s): Stephen T. Steve() Stark
Abstract/Introduction:
First developed in the middle 1960s, modern-era electronic natural gas flow computers came into wider use for custody transfer measurement beginning in the late 1970s. In the 1980s and 1990s, improvements in charging systems, microprocessors, and transducers made flow computers much more practical for everyday use even in remote locations. In the earlier days, gas flow computers were used to calculate flow - and not much more. Today in 2009, flow computer systems do much more than just measure flow, providing extensive amounts of data while also performing many tasks that are necessary in todays complex and fast-moving energy industry. In this brief article, we will focus only on the gas measurement-related issues that are relevant to testing, maintenance, and operation of natural gas flow computers.
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Document ID:
121EF7E9
Transient Lightning Protection For Electronic Measurement Systems
Author(s): Dan Mccreery
Abstract/Introduction:
Energy supply is now a critical part of todays economy. This fact places increasing demands of reliability and availability on the control systems we use in this industry. Maximum availability and system reliability is mandated for both safety and maximum profitability. While considerable effort is expended in the evaluation of methods to improve processes, many engineers have yet to grasp the threat lightning and surges pose to modern control systems. As we have moved from analogue to digital control, from TTL to IC logic, our instrumentation and control equipment have become much more sensitive to voltage spikes. TTL components could sustain damage from an impulse with as little energy as 10J. Todays IC logic can be damaged from an impulse with as little as 1J of energy. It is very important that the protective systems we use today are designed to address todays modern and more sensitive equipment as well as the higher demands for improved uptime and reliability.
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Document ID:
0AE3758A
Calibration Of Liquid Provers
Author(s): William R. Young Jr.
Abstract/Introduction:
A meter prover is used to calibrate custody transfer meters to establish a meter factor. The volume that passes through the meter is compared to the prover volume during the time taken for a sphere or piston to pass between two detector switches. The prover volume must be accurately determined by a calibration procedure known as the Water Draw method.
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Document ID:
DBC7606B
Design, Calibration, And Operation Of Volume Standards
Author(s): Sherry Sheckels
Abstract/Introduction:
Test measures are designed to deliver a known liquid volume when drained. Their primary use is to calibrate displacement and tank provers in the field by the waterdraw method.1, 2 Accurate test measure volume calibrations are critical to achieving low uncertainty calibrations with flow provers in the field. Test measures can either be invertible or bottom-drain type. Invertible test measures are usually less than 40 L (10 gal) while bottom-drain test measures are larger than 40 L (10 gal). Each year, approximately 100 test measures used for field calibrations are calibrated at the National Institute of Standards and Technology (NIST) to comply with API standards.3 NIST uses several calibration methods depending on the size of the test measure: 1) the gravimetric method, 2) the gravimetric transfer method, and 3) the volumetric method.4 NIST calibrations include a neck scale calibration at five levels spaced over the range of the neck scale. To ensure accurate customer calibrations and to maintain an ISO 17025 compliant quality system5 NIST regularly performs calibrations of the 60 kg and 600 kg balances used during the calibration and calibrates volume check standards.
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Document ID:
E20951D3
Calibration With Pneumatic Dead Weight Testers
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:
954294E6
Flow Calibrating Ultrasonic Gas Meters
Author(s): Joel Clancy
Abstract/Introduction:
The primary method for custody transfer measurement has traditionally been orifice metering. While this method has been a good form of measurement, technology has driven the demand for a new, more effective form of fiscal measurement. Ultrasonic flowmeters have gained popularity in recent years and have become the standard for large volume custody transfer applications for a variety of reasons. Most users require flow calibrations to improve meter performance and overall measurement uncertainty. The latest revision of AGA Report No. 9, Measurement of Gas by Multipath Ultrasonic Meters, Second Addition Ref 1, now requires flow calibration for ultrasonic flow meters when being used for custody transfer applications. What considerations then, should be taken when choosing to flow calibrate an ultrasonic flowmeter? What are the benefits to the user? What should a user expect from a flow calibration? What kind of performance should the customer expect or accept from an ultrasonic meter? What are the diagnostic capabilities inherent in an ultrasonic meter? These areas, as well as others will be explored and considered.
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Document ID:
31778D87
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:
CA5C8A84
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).
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Document ID:
60EE61C8
Lact Unit Proving - The Role Of The Witness
Author(s): Art Casias, Terry Ridley
Abstract/Introduction:
Witness, as defined by the New Websters Dictionary, 1.n, a person who has observed a certain event, the unwilling witness of a quarrel a person who testifies to this observation, esp. in a court of law, and esp. under oath a person who testifies to the genuineness of a signature on a document by signing his own name to the document an authentication of a fact, testimony public affirmation of the truths of a religious faith something taken as evidence, to bear witness to declare, on the strength of personal observation, that something is true to give as evidence, to bear witness, knowledge, testimony. The role of the witness, in the proving of a LACT unit, requires you to understand the operations of both the LACT and ACT units and the device used in proving their accuracy.
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Document ID:
F504D20D
Liquid Flow Provers
Author(s): Ruud Bos
Abstract/Introduction:
For many years meter proving has been carried out within the industry and many methods to achieve this have been developed over time. This following document will focus on the different types of meter proving done and their characteristics. Since Honeywell Enraf builds small volume provers the document will describe the way small volume provers are constructed and operated in more detail.
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Document ID:
F29DEFC4
Liquid Meter Proving Techniques
Author(s): Peter P. Jakubenas
Abstract/Introduction:
This paper will cover the techniques that are important for proving various types of liquid meters in accordance with API Chapter 4.8. As the price of crude oil and refined products increases the need for proving and proper equipment and techniques for proving becomes more important and the justification for investment in proving equipment and maintenance of the equipment becomes easier. Mis-measurement of even 0.05% on a stream flowing at 2,000 BPH or 48,000 BPD of 50 crude oil costs 439,000 per year. Under-registration deprives the company of entitled revenue, over registration raises the issue of customer complaints, retroactive rebates, and potential lawsuits.
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Document ID:
7926BB75
Operation & Problems Associated With Prover Detector Switches
Author(s): Warren A. Parr, Jr.
Abstract/Introduction:
In many parts of the petroleum industry, sphere provers are used to dynamically calibrate volumetric meters. In order to accomplish this, sphere provers are required to be accurate and repeatable. This accuracy and repeatability is largely dependent on performance of the prover sphere detector. Any operational or design problems associated with the prover detector will affect the provers performance. This paper will review critical parts of a prover sphere detector that must be checked in order to obtain accuracy reliability and repeatability. The areas that will be covered are:
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Document ID:
5BE0BFA3
Operational Experience With Small Volume Provers
Author(s): Steve Whitman
Abstract/Introduction:
Introduced decades ago, Small Volume Provers (SVPs) are now common technology. There are numerous publications providing empirical data and outlining the technical operation of this equipment. The following document will focus on the authors experience, addressing common concerns and questions regarding SVPs.
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Document ID:
DDFC02F6
Proving Coriolis Meters
Author(s): Marsha Yon
Abstract/Introduction:
Coriolis meters are in use throughout the hydrocarbon industry for the measurement of fluids including crude oil, products such as fuel oil, gasoline, and diesel, and light hydrocarbons such as natural gas liquids, propane, etc. When used for custody transfer, it is most often required by contract between the buyer and seller that the meter be proven in the field on the fluid that is being measured and at the conditions under which it will be operating. This paper will utilize the American Petroleum Institutes Manual of Petroleum Measurement Standards (MPMS) as the reference for industry practices for field proving methods and calculations.
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Document ID:
AEEAFA8A
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:
629F14D4
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:
84D514FC
Witnessing Orifice Gas Measurement And Field Testing
Author(s): Olen Douglass
Abstract/Introduction:
The natural gas industry is an ever changing field. While the basic concept of orifice measurement remains the same, new methods of obtaining and storing data are constantly being introduced. Because of this, the need for witnessing orifice gas measurement and field testing is more important than ever.
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Document ID:
2CDA3043
Improving Flow Measurements With Improved Calibration And Data Handling Procedures
Author(s): Duane Harris
Abstract/Introduction:
The knowledge base from a field measurement technician to a back office volume analyst is extremely demanding. Every field technician is tested in both knowledge and skills on a daily basis for: ? electronic controls to pneumatic controls ? communication system support ? multiple disciplines ? support of measurement equipment ? procedures that must be followed ? regulatory requirements governing the facilities ? ongoing training of field personnel
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Document ID:
0F5E447B
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:
F5E17B7F
Btu Analysis Using A Gas Chromatograph
Author(s): James W. Bowen
Abstract/Introduction:
Gas Chromatographs, or GCs, are commonly used to analyze both liquid and gaseous hydrocarbons, from which analysis the heating value of the sample can be calculated. Following is an explanation of how GCs operate, how calculations of heating value are made and discussion of elements of the GC that can be monitored and trouble shot to insure that correct heating value results are obtained. GCs are configured in a variety of ways depending on the operating environment and gas to be analyzed, but the operating principle is common to all types. Consideration in this paper is limited to on-line units typically installed in field or industrial environments.
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Document ID:
40DEB8FB
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 they 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:
05EC5F2D
Chromatograph Maintenance And Troubleshooting
Author(s): Shane Hale
Abstract/Introduction:
Natural Gas is sold as Energy. Gas Chromatographs calculate the Energy value of the Gas (as well as other calculated values used in the Flow Calculation). When there is only a single Gas Chromatograph (GC) on a Custody Metering station, the downtime for a GC must not only be at a minimum but it should be planned ahead of time, rather than occurring only when a failure has occurred. To allow for predictive maintenance an appropriate maintenance program should be instituted so that analysis problems are identified before they cause measurement errors. Thus maintenance can be performed on a predictive basis, rather than on an ad-hoc or breakdown basis. This paper will describe the routine maintenance that should be performed on a Gas Chromatograph System, the predictive diagnostics steps that should be used, and finally outline the steps taken to perform an overhaul of the analysis system.
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Document ID:
AB19D5D7
Chromatographic Analysis Of Natural Gas Liquids
Author(s): Darville Dee Orr Jr.
Abstract/Introduction:
With the changes in the economy as well as advances in technology in production of chemical, pharmaceuticals, and other products, the demand for NGL has changed which has a dramatic result in the value of NGL. The result of these conditions demands an accurate analysis and measurement of the NGL for the companys balance sheet and bottom line.
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Document ID:
FC530D08
Determination Of H2S And Total Sulfur In Natural Gas
Author(s): Thomas Y. Tramel
Abstract/Introduction:
Hydrogen Sulfide (H2S) is a chemical compound comprised of one Sulfur Atom and two Hydrogen Atoms. It is a colorless, extremely poisonous gas that reeks of rotten eggs. Hydrogen Sulfide is highly corrosive and renders some steels brittle, leading to sulfide stress cracking. Hydrogen Sulfide is formed when bacteria breaks down organic matter in the absence of oxygen and therefore is often found in crude oil and natural gas deposits. Due to the toxic and corrosive properties of Hydrogen Sulfide and its natural presence in natural gas, it is imperative to measure and control of the concentration levels of this compound within natural gas pipelines. This paper will address the properties, purpose of measurement and measurement methods for H2S and discuss how these methods can be adapted to the measurement of Total Sulfurs as well as H2S in natural gas streams.
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Document ID:
E7232D79
Determination Of Water Vapor Content In Natural Gas
Author(s): Murray Fraser
Abstract/Introduction:
Gas Quality Analysis encompasses a variety of technologies and sample handling challenges for field analyzers and operations personnel. This paper will focus on moisture analysis in Natural Gas using new laser-based technologies known as Tunable Diode Lasers or TDL. In addition the paper will discuss conventional technologies for moisture analysis. Additional topics will include best practices for sample conditioning in -40C operating environments and an in-depth review of actual field conditions where disputed moisture measurements were a concern at an inter-company custody transfer point in Alberta. Observations, recommendations and validation procedures will be presented that may be useful anytime the dew point of natural gas is in dispute.
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Document ID:
20167D2B
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 analysis 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.
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Document ID:
16F47CC4
Determination Of Hydrocarbon Dew Point In Natural Gas
Author(s): Ray N. Adcock
Abstract/Introduction:
The reasons for monitoring the dew-point of natural gas for custody transfer and transport are well understood. High levels of water in a natural gas stream can lead to corrosion, hydrate formation, and freezing (cryogenic processes). Hydrocarbon (HC) dew-points in natural gas can lead to pooling of liquids at low points in the pipeline, variations in the BTU content of the gas, and hot spots on compressor-turbine blades.
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Document ID:
C6BF2277
Hydrocarbon Dew Point Effects On Gas Flow Measurement
Author(s): Fred Van Orsdol
Abstract/Introduction:
The hydrocarbon dewpoint (HCDP) of interest to the natural gas industry is simply an operating condition that causes liquids to condense out of the gas stream and form a liquid phase. Normal condensation occurs when increasing pressure or decreasing temperature causes liquids to form. Retrograde condensation occurs on a different portion of the phase envelope, wherein increasing temperature or decreasing pressure may cause the gas to cross the phase boundary and produce condensation. Both processes produce liquids condensing out of gas phase streams and are of interest to this presentation. Phase diagrams will not be discussed further in this paper, other than to mention that present correlations to predict phase behavior have proven to be inaccurate for relatively rich gas streams and typically predict HCDP temperatures well below the actual HCDP temperature. I will try to characterize rich gases, as referred to in this paper, by indicating those at or above 1050 Btus per cubic foot and containing some C4 thru C6+ components (butanes thru natural gasoline).
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Document ID:
33106700
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.
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Document ID:
7BBF0384
Energy Measurement Using Flow Computers And Chromatography
Author(s): Burt Reed
Abstract/Introduction:
The means and methods of transfer of quantities of natural gas between buyers and sellers have been changing for many years. When coal gasification was used to fuel the streetlights in Atlanta, Ga. There was no reason to even measure the commodity. The municipality generated the gas, transported it, and burned it. When Frank Phillips started purchasing gas rights back in the 1930s, every one thought he was more than odd.
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Document ID:
C8CF61F9
Energy Measurement Utilizing On-Line Chromatographs
Author(s): Derrill Meyer
Abstract/Introduction:
In most cases today, natural gas custody transfer contracts have an energy specification and use MMBtu1 (million Btu) as the standard unit of measure rather than just gas volume. A Btu, British thermal unit, is a measure of heat or Calorific Value, CV. One Btu is the quantity of heat required to raise the temperature of one pound of water from 58.5F to 59.5F (Approx. CV 1055.056 Joules SI2). Heat is regularly gained by the burning of natural gas, and as the energy content of the natural gas increases, so does the heat (energy) received from burning it. For example, to heat a home with natural gas that is 1050 Btu/Scf will require less gas volume than using natural gas that is 980 Btu/Scf, as the Btu value is the actual amount of heat energy contained in a cubic foot (cf) of this natural gas. The combination of volume and Btu measurements enable companies to bill on an energy basis. Since natural gas markets as a whole are making transactions based on energy, it has become increasingly important at lower and lower volumes to calculate real time energy flow rates.
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Document ID:
A2D59B22
Field And Laboratory Testing Of Sediment And Water In Crude Oil
Author(s): Del J. Major
Abstract/Introduction:
In this paper we will discuss the different methods of determining the quantity of sediment and water content in crude oil. We will also discuss some of the problems associated with the field-testing methods and attempt to better understand how those problems affect your Companys bottom line. Custody transfer of crude oil takes place by determining the quantity and quality of the product exchanging ownership. Precise and accurate measurement with minimal bias errors is essential in custody transfer applications. Although sediment and water determination is often thought of as a quality indicator, it actually affects the quantity since its quantity is deducted from the final volume transferred. The allowable amount of sediment and water that can be accepted is based on tariff restrictions that are spelled out by the transporting Company or system.
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Document ID:
20744E37
Fundamentals Of Gas Chromatography
Author(s): Derrill Meyer
Abstract/Introduction:
Btu is the three letter acronym for British thermal unit. One Btu is the quantity of heat required to raise the temperature of one pound of water from 58.5 F to 59.5F (about 1055.056 joules (SI)). Heat, Btus, is gained from the burning of Natural Gas, that is Oxidation, as is shown in the chemical equations below: ? CH4 + 2O2 CO2 + 2H2O + HEAT (1010 Btu/CF) ? 2C2H6 + 7O2 4CO2 + 6H2O + HEAT (1769 Btu/CF) ? C3H8 + 5O2 3CO2 + 4H2O + HEAT (2516 Btu/CF) This HEAT is the valuable commodity that makes Natural Gas production, transmission and distribution profitable as an enterprise. The purpose of this paper is to describe how this heat amount can be obtained from the gas composition. The method for attaining this composition will also be discussed.
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Document ID:
20C8D310
Heat Quantity Calculation Relating To Water Vapor In Natural Gas
Author(s): Edgar B. Bowles, Jr.
Abstract/Introduction:
Natural gas oftentimes contains some amount of water, in either vapor or liquid form. The solubility of water in natural gas flowing through a pipeline is a function of the pressure and temperature of the flow stream. The amount of water affects the heating (calorific) value per unit volume of natural gas. The more water present in the gas, the less valuable it is as a fuel, since the water does not burn. This water, in vapor form, is sometimes referred to as spectator water and it displaces the hydrocarbon components in a natural gas mixture. The net effect is a reduction in heating value and monetary value per unit volume of gas. The amount of water vapor contained in a natural gas mixture is customarily expressed in terms of the mass of water per unit volume of gas for example, pounds mass of water per million standard cubic feet of natural gas (lbm/MMSCF).
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Document ID:
12DA5B12
Measurement Of Lpg
Author(s): Fred Van Orsdol
Abstract/Introduction:
Liquefied Petroleum Gases (LPGs), serve as a valuable source of chemical plant and refinery feedstock, and as a clean burning fuel. LPG is typically a product of gas processing plants or refineries. Gas plants typically produce a raw mix natural gas liquid stream which is later fractionated into useful products such as purity ethane, ethane/propane mix, propane, Iso-butane, normal butane, Iso-pentane, normal pentane and natural gasoline mix. Some gas processing facilities have their own fractionation capability and may produce the same products as the dedicated fractionators. Refineries produce propane, but heavier products such as the butanes and pentanes and natural gasoline are used within the refinery and not typically marketed as a specification product.
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Document ID:
5E208CA4
On Line Water Measurement Devices In Liquid Service
Author(s): Kim Mohajer
Abstract/Introduction:
In todays competitive energy market there is a tremendous emphasis on cost saving and productivity at all levels of the industry. Online water detection provides vital real-time information regarding water concentrations in hydrocarbons empowering the user with the knowledge necessary to maximize efficiencies and cost savings while increasing many safety factors at the same time. The installation of On line Water Detectors or OWDs (also called Water Cut Meters) in pipeline or bypass analyzer loop systems has obvious key benefits at any stage involving custody transfer. Even with currently moderate crude oil prices, paying for shipped water is a hugely punitive and now unnecessary cost to energy companies. But OWDs can improve, automate and optimize several other key stages leading to refined materials. Chief among those are production and tank water draw automation.
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Document ID:
E7FA1A99
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:
C58933A9
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.
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Document ID:
934A6FB8
Techniques Of Gas Composite Sampling
Author(s): Phil Rutledge
Abstract/Introduction:
Hopefully everyone who is responsible for obtaining a gas sample has been properly trained as to how this is to be done. There is always a concern in this area because of the many different sampling methods and techniques however, one of the biggest concerns is how many of us are properly following all these steps? Another concern is did the person doing the training pass on any bad habits or incorrect steps. On the job training with out having a correct SOP to follow can often enhance this problem. Another potential error maybe the Alphabet Soup of Measurement Standards such as API, AGA, GPA, etc. may not always be available to the technicians so a homemade method or bad assumptions can be developed by the person doing the sampling. It is also critical we sample correctly because of the potential BTU variance, which could occur if we make mistakes with the design or set up of the sample apparatus. Ask yourself, can a three percent error or variance occur from poor sampling methods? The answer is a big yes?
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Document ID:
6185C13C
Techniques Of Gas Spot Samples
Author(s): David J. Fish
Abstract/Introduction:
The amount of hydrocarbon product that is transported between producer, processor, distributor and end-user is significant. To be able to verify the exact composition of the product is important from an economic and product treatment standpoint. A small percentage savings made by correctly determining composition will quickly recoup the time and investment made into proper equipment designed to obtain an optimum sample. In addition, if the best sampling procedures are followed, the potential for disputes between supplier and customer will be greatly reduced. The importance of properly determining hydrocarbon gas composition benefits all parties involved and will achieve greater significance as this precious commodity becomes less plentiful and more expensive.
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Document ID:
A8D56449
Determination Of Hydrocarbon Dew Point Using A Gas Chromatograph Determining Hydrocarbon Dew Point Per Gas Chromatographic Analysis And Equations Of State
Author(s): Shane Hale
Abstract/Introduction:
The determination of the Hydrocarbon Dew Point (HCDP) for Natural Gas has recently become a critical issue for the Natural Gas industry due to the rapid expansion of interconnecting pipelines and the rise of the Liquefied Natural Gas (LNG) as an international source of Natural Gas. Where previously the Natural Gas in a pipeline would come from a small number of known producers, the Natural Gas flowing through the pipeline today could have come from many varied sources including traditional Gas Plant producers (De-hydration, CO2 and/or N2 control and removal of Condensates), Coal Bed Methane producers (98% Methane), low cost producers (De- Hydration only) or global exporters of LNG.
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Document ID:
4951CBB2
Fundamentals Of Sampling Natural Gas For Btu Determination
Author(s): Donald P. Mayeaux
Abstract/Introduction:
It has long been recognized that the largest source of error in the analysis of natural gas is the sample conditioning system (SCS). The sample conditioning systems consist of all components through which the sample gas travels from its source, typically a pipeline, to the gas chromatograph (GC) inject valve. The purpose of the sample conditioning system is to extract a natural gas sample that is representative of the source, transport it to an on line gas chromatograph, and in the process condition it so that it is compatible with the analyzer. Conditioning consist mainly of excluding unwanted liquids and solids, regulating the pressure and flow, and heating to maintain the sample gas well above its hydrocarbon dew point temperature(1). During the entire sample conditioning process the sample gas must not undergo any changes in its composition.
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Document ID:
B07D9E72
Moisture Measurement Using Laser Spectroscopy
Author(s): Samuel C. Miller
Abstract/Introduction:
The need for reliable moisture measurement is essential to natural gas companies because of the corrosive nature of the moisture in combination with compounds such as carbon dioxide and hydrogen sulfide. Natural gas processors and pipeline operators must measure moisture and other contaminants to protect equipment and to conform to customer specifications. Since TDL analyzers provide very fast and reliable measurements, they are commonly used in the control loops of purification, separation, and liquefaction processes to optimize efficiency and costs. This paper will review the background of TDL spectroscopy, the theory of operation, and the measurement performance that can be achieved. It will also cover installation issues that are important to getting good measurements and it presents data comparing TDL measurements to a Bureau of Mines type chilled mirror. TDL spectroscopy can provide accurate measurements of moisture as well as carbon dioxide and hydrogen sulfide in natural gas much faster and more reliably than other methods.
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Document ID:
5135B246
CO2 Determination Of Natural Gas Streams
Author(s): Charlie Cook
Abstract/Introduction:
Carbon Dioxide is measured in Natural Gas for two reasons. First and most often it is measured for energy determination (BTU/CV) by gas chromatography. And the second reason CO2 is determined is for pipeline integrity. The measured data is transmitted in various ways for records keeping as well as operational input. CO2 measurement for energy determination is typically made by gas chromatography. Gas Chromatography is employed in two ways - on line gas chromatography which is used primarily for custody measurement in larger meter stations or by laboratory measurement of composite samplers.
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Document ID:
EA4E12EB
Considerations For Sampling Wet, High Pressure, And Supercritical Natural Gas
Author(s): Donald P. Mayeaux
Abstract/Introduction:
This paper discusses the problems encountered when sampling wet, high pressure and supercritical natural gas for on-line BTU analysis, and provides solutions and comments on how they relate to the API and GPA industry standards for natural gas sampling. It also discusses the use of phase diagrams in the design and operation of a natural gas sampling system.
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Document ID:
D8086D46
Flare Measurement Advanced Ultrasonics
Author(s): Curtis Gulaga
Abstract/Introduction:
There has been an increased awareness by oil and gas companies in North America toward emissions monitoring and reduction for both environmental and economical reasons. For years, several countries worldwide have had stringent regulations in place. Regulations were implemented in 1993 relating to the measurement of fuel and flare gas for calculation of CO2 tax in the petroleum activities on the Norwegian continental shelf. Inevitably, oil companies operating in the region had to comply with these regulations. With new government legislation, producers, refineries and chemical companies have been looking for a cost effective solution to reduce emissions and to provide tighter control for both leak detection and mass balance. To tolerate the extreme process conditions often found in a flare line, yet provide accurate measurement to comply with international regulators such as the Energy Resources Conservation Board in Canada, the European Union, or the Texas Commission of Environment Quality, the technology of choice is important. Several metering technologies have been tested with little success. To understand why the results have been dismal, one needs to fully understand the challenges associated with the application. Further investigation towards the effects of sonic noise generated from high gas velocities, elbows, Ts, and pipe segments, has been conducted and the results detailed in this paper.
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Document ID:
4F6B1941
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:
377D60AA
Controlling Surges In Liquid Pipelines
Author(s): Ron Kennedy
Abstract/Introduction:
Numerous technical papers have been written on unsteady state surge flow or water hammer. This paper, unlike many of its predecessors, will present a view adapted to the engineer/technician who, for one reason or another, only needs a basic understanding of why surge occurs and how to control it. This paper will discuss the following topics: 1. History 2. Definitions/terminology 3. Why surge occurs 4. Problems from inadequate surge protection 5. Controlling Surges
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Document ID:
A38AAB0E
Fundamentals Of Pressure Regulators
Author(s): Thomas Weyer
Abstract/Introduction:
Gas pressure regulators have become very familiar items over the years, and nearly everyone has grown accustomed to seeing them in factories, public buildings, by the roadside, and even in their own homes. As is frequently the case with many such familiar items, we all have a tendency to take them for granted. It is only when a problem develops or when we are selecting a regulator for a new application that we need to look more deeply into the fundamental of the regulators operation.
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Document ID:
5EB1F9F6
Overpressure Protection Methods
Author(s): Thomas Weyer
Abstract/Introduction:
Overpressure protective devices are of vital concern to the gas industry. Safety codes and current laws require their installation each time a pressure reducing station is installed that supplies gas from any system to another system with a lower maximum allowable operating pressure. The purpose of this article is to provide a systematic review of the various methods of providing the overpressure protection. Advantages and disadvantages of each method are evaluated, and engineering guidelines are provided.
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Document ID:
7CFE0CC3
Prevention Of Freezing In Measurement And Regulating Stations
Author(s): Tom Fay
Abstract/Introduction:
One way businesses in todays natural gas industry can be certain to maintain a presence in a competitive market is to be able to deliver a consistent supply to their customers. To ensure a reliable supply, companies must be aware of potential problems that could lead to interruptions or shutdowns in service and the procedures that can prevent these costly situations. Freezing is a major culprit not only in these pipeline shutdowns and interruptions, but it can also affect the accuracy of gas measurement.
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Document ID:
55AED41D
Selection, Sizing, And Operation Of Control Valves For Gases And Liquids
Author(s): Ross Turbiville
Abstract/Introduction:
Proper control valve sizing and selection in todays industrial world is essential to operating at a cost-effective and highly efficient level. A properly selected and utilized control valve will not only last longer than a control valve that is improperly sized, but will also provide quantifiable savings in the form of reduced maintenance costs, reduced process variability, and increased process availability. An undersized valve will not pass the required flow, while a valve that is oversized will be more costly and can cause instability throughout the entire control loop. In order to properly size a control valve, one must know the process conditions that a given valve will see in service. Proper valve selection is not based on the size of the pipeline, but more importantly, the process conditions and a combination of theory and experimentation used to interpret these conditions.
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Document ID:
6D6D87A0
Turbulence And Its Effect In Measurement And Regulating Stations
Author(s): Mike Mckay
Abstract/Introduction:
When one thinks of turbulence, what is the first issue which comes to mine? NOISE!!!. The true being, turbulence causes far more issues, than just noise. There is vibration, showing up as pipe fatigue, Noise and Discomfort, shows in the accuracy in measurement, a person rushing to complete his or hers job, resulting in a lower quality of work. The capacity of a station, the volume desired not being able to achieve vs. the volume which the station was design to deliver. Turbulence in any pipeline system is not an asset Both engineers and field personnel alike are equally interested in keeping turbulence to a minimum. Engineering looking for maximum throughput and the field personnel the best site for Analytical equipment or sense point for the control system, and good measurement.
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Document ID:
2174D783
Allocation Measurement
Author(s): Jeffrey L. Savidge
Abstract/Introduction:
Allocation is the process of assigning the proper portions of aggregated product flows back to individual source streams, owners, leases or measurement point. The assignment process is a standard method that is agreed upon and used by contracting parties. It is designed and intended to be fair, cost efficient and practical. By providing an efficient product sales transaction mechanism, allocation measurement helps to reduce capital and operating costs without jeopardizing the principal goal of fair treatment among parties. Reducing fluid measurement costs facilitates the development of marginal fields.
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Document ID:
F647CCBF
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:
11FCD14B
Auditing Electronic Gas Measurement Per API Chapter 21.1
Author(s): John Renfrow
Abstract/Introduction:
The American Petroleum Institute, Manual of Petroleum Standards, Chapter 21.1 Flow Measurement Using Electronic Metering Systems, describes the minimum specifications for Electronic Gas Measurement (EGM) systems used in the measurement and recording of flow parameters of gaseous phase hydrocarbons and other related fluids for production and transmission custody transfer applications utilizing industry-recognized measurement devices. The intent of this paper is to address the different auditing requirements of API Standard 21.1 and most common measurement adjustment issues.
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Document ID:
DDF4F3CF
Auditing Gas Measurement And Accounting Systems
Author(s): Stephen T. Stark
Abstract/Introduction:
Gas measurement and accounting system auditing has gradually become somewhat more complex as electronic flow measurement and other computer-based technologies have arrived on the scene. Before the early 1990s, measurement auditing was often little more than verifying chart integration and struggling through piles of field test slips looking for missed orifice plate changes, incorrect gas quality information, and unnoticed calibration adjustments. Today, however, gas measurement auditing is more complicated than ever before as gas companies rely on high-speed communication and computer networks to gather massive amounts of information required in todays fast-paced energy industry. Flow rates, total energy, pressures, temperatures, gas quality, flow factors, meter performance data and a lot more is included in this enormous information mix.
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Document ID:
543D781A
Auditing Liquid Measurement
Author(s): Linda A. Larson
Abstract/Introduction:
Presented by Ed J. Saccomanno, Internal Auditing Manager, Motiva Enterprises LLC, 700 Milam, Room 11036, Houston, Tx 77002, e-mail: ed.saccomanno@motivaent.com. 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:
A5151243
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:
1B2C1BAE
Sarbanes-Oxley Act And Its Impact On Measurement Discussion Of The Effect Of Sox Requirements On Measurement
Author(s): Lisa Walker
Abstract/Introduction:
Sarbanes Oxley (SOX) is legislation that is here to stay. Sarbanes Oxley (SOX) has been around now for almost seven years and since its implementation it has not only evolved and become more defined, it has remained as robust as ever. Many companies have already reviewed and implemented controls and remediated any gaps that may have existed when the audit process began. Annual reviews of controls insure that once implemented, SOX will be forever embedded in the fabric of every publicly traded company. Through the utilization of SOX guidelines strong controls have emerged which have helped establish well documented, more efficient measurement and company processes. The benefit of knowing the facets of our business from beginning to end as well as finding where any opportunities for false or even fraudulent processes may be found have been invaluable . A more evolved sense of integrity and pride in our positions and knowing exactly where our companies stand with regards to the importance of good measurement and good solid practices has been beneficial for all employees.
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Document ID:
6CBA3D2B
API Mpms Chapter 22.2 - Testing Protocol For Differential Pressure Flow Measurement Devices
Author(s): Casey Hodges
Abstract/Introduction:
The performance characteristics of a new metering device can be determined in many ways. From the testing mechanism to the formatting, analysis, and presentation of the results, a consumer can have a very difficult time determining if two meters are comparable. For differential producing flow meters, there is only one meter type that standards have been developed for, the orifice plate. These standards are based upon decades of research and development. Even orifice plate standards are continually being updated based on current technologies and capabilities. For any other differential producing meter, there was no protocol by which the performance of the meter could be quantified. This paper describes the development of API MPMS Chapter 22.2 Testing Protocol - Differential Pressure Flow Measurement Devices, demonstrates how the standard is used, and discusses issues that exist when using differential meters.
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Document ID:
43A839FF
Overview Of AGA 7 Revision
Author(s): Angela Floyd
Abstract/Introduction:
Just when you thought you knew everything there was to know about turbine meter measurement, wham, out comes a revised AGA 7 standard. Now those basic principles are all still valid but maybe those operating practices we have built into our operating procedures need a little review. Rather than proceed as generations have done before us, research has been completed on the meters, their installation and operating practices and the way we calibrate and field test them. So now we have some data to back up our methods and madness.
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Document ID:
18D01062
Overview Of AGA 9 Revision
Author(s): John Lansing
Abstract/Introduction:
The American Gas Association published Report No. 9, Measurement of Gas by Multipath Ultrasonic Meters Ref 1 in June 1998. It is a recommended practice for using ultrasonic meters (USMs) in fiscal (custody) measurement applications. This paper reviews some of history behind the development of AGA Report No. 9 (often referred to as AGA 9), key contents and includes information on meter performance requirements, design features, testing procedures, and installation criteria. This paper also discusses changes that will be incorporated in the next revision. At the time of this paper the expected publication date is the Fall of 2006.
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Document ID:
C41DA1BE
Overview Of Gpa 2172/API 14.5 Revision
Author(s): Don Sextro
Abstract/Introduction:
GPA Standard 2172-09 / API Manual of Petroleum Measurement Standards Chapter 14, Section 5, Calculating Gross Heating Value, Relative Density, Compressibility and Theoretical Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody Transfer, Third Edition, January 2009 finds wide application in the natural gas gathering and processing business as well as related natural gas handling activities because it provides methods to calculate these often-used parameters from a gas analysis. Several important changes occurred in the recent revision of this standard that became effective January 1, 2009. The main changes comprised in this revision provide methods for incorporating water vapor into the analysis calculations, include theoretical hydrocarbon liquid content (GPM) calculations on a real gas basis in this standard, discuss characterizing heavy ends in the gas analysis as well as other analysis cautions and providing a number of detailed example calculations. Refer to the standard itself for requirements, procedures, details and further explanation.
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Document ID:
AB54CA13
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.
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Document ID:
94AAEB3B
Combining Intrinsic Safety With Surge Protection In The Hydrocarbon Industry
Author(s): Don Long
Abstract/Introduction:
The Hydrocarbon Measurement Industry faces a rather unique combination of problems. First, many of the areas in and around pumping, custody transfer and storage areas are classified, or hazardous, that must, according to the National Electric Code, be assessed for explosion-proofing. This may be in the form of intrinsic safety barriers or isolators, explosion-proof enclosures and conduits, purged enclosures or nonincendive components. The second challenge facing the industry is the physical exposure of most of the electronic control and measuring systems, communications, and power subsystems, each with their own sensitive, high-performance microprocessors, etc., to potentially devastating lightning and electrical surges. Key to the successful application of both intrinsic safety (I.S.) and lightning/surge protection is proper grounding. The goal of this discussion then is to briefly summarize these two technologies and then to take a detailed look at the commonly misunderstood subject of grounding in the instrument and control system or IACS.
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Document ID:
D85B174E
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:
2257DE89
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.
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Document ID:
4965FB40
Interface Detection In Liquid Pipelines
Author(s): Vicky Garza
Abstract/Introduction:
The basic concept of interface detection is simple: detect and direct the flow of different fluids, or batches, through pipelines. The implementation, however, can be very complicated. The goal of interface detection is to time the switching or cut of the product in such a way that delivers the maximum quantity of product to customers without downgrading the quality of the product. Inaccurate interface detection leads to an increase in both downgraded product delivery and transmix, which requires storage and additional refining. Both significantly cut into the profit margins on delivered product. Historically interface detection was facilitated by batching fuels of dissimilar densities against each other in the pipeline. The interface could then be detected using time-based displacement with manual sampling, or density measurements from metering stations and/or add-on sensors.
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Document ID:
FDABBC86
Multiphase Flow Measurement
Author(s): Richard Steven
Abstract/Introduction:
The measurement of unprocessed hydrocarbon flows is becoming more prevalent in the hydrocarbon production industry. Multiphase meters are now often integral in the design plans for new developments. However, the phrase multiphase flow covers a huge range of flow conditions and metering these varied flows has proven a major challenge to engineers. Multiphase meters are a relatively recent technology in the oil and gas production industry. They tend to be relatively complex and proprietary in nature. Therefore, there can be a lack of technical understanding amongst the multiphase meter users. In this paper, there will be an introduction to multiphase flow terminology, multiphase flow patterns and an overview of generic multiphase metering techniques.
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Document ID:
BC4249A4
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:
B3A6AF40
Orifice Meter Tube Dimensional Tolerances
Author(s): Ken Embry
Abstract/Introduction:
The orifice meter is the most predominantly utilized device for measurement of natural gas. Its dominant presence in the natural gas industry stems from many years of acceptance as the primary means for accurate measurement. In 2000, revised manufacturing and inspection standards, along with new technology for flow enhancement have improved the overall accuracy of orifice metering. Though other measurement devices and technologies have made significant impact, the orifice meter offers stands as the dominant device for several reasons: - Rugged construction that stands up to many applications - No moving parts involved in the measuring process - Relatively inexpensive to manufacture and maintain - Proven and accepted technology - Dimensional calibration is accepted in lieu of flow calibration
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Document ID:
80341BCD
Program For Training A Measurement Technician
Author(s): Allen N. Chandler
Abstract/Introduction:
The need for quality measurement has increased dramatically in the past several years. Deregulation of market pricing structures, open access markets, increased exploration and drilling costs, fierce competition, and new regulatory requirements have all influenced todays approach to quality measurement methodologies. In fact, the terminology has evolved from gas volume measurement to total energy measurement. Today not only is the volume of gas a consideration, but also the quantity of energy the gas produces. Our industry has transitioned from the MMCF to the MMBTU for gas measurement.
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Document ID:
C7884AE1
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:
F89920A4
Meter Selection
Author(s): Harvey Stockman
Abstract/Introduction:
Natural gas meter selection is based on a variety of factors: the most important of which are safety and accuracy. Other significant factors include repeatability, defensibility through adherence to contractual and/or regulatory requirements and industry standards, cost effectiveness, reliability, and uniformity with existing installations. This paper will briefly discuss commonly used high pressure gas meters, their basic functionality, applicable standards, installation and operating considerations based on the authors experience and a review of industry standards and literature, their turndown, and specific examples of recent meter selections for specific applications.
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Document ID:
9CBC3E81
Cone Meters For Liquid And Gas Measurement
Author(s): Philip A Lawrence
Abstract/Introduction:
This paper will describe how cone meters whilst similar in principle differ operationally from other types differential pressure type meters and how they are used for the measurement of liquid and gas. The cone meter has become synonymous with specialist metering applications over many years due to special traits that are inherent in this type of meter design. The original cone meter concept was taken from the Venturi original design in 1791 by Hershel and other variants like Burton Dunlinsons Inverse Venturi (Patented in 1935). Cone meters have been used on many fluids such as Steam, Wet Gas , Liquids that have trash, asphaltenes and wax in pipes together with applications that have installation issues such as short meter runs lengths (usually off-shore).they have been used for custody transfer with user-party agreements and have been quite successful through the years in other industrial applications such as water measurement, some of the key ideas that enabled these concepts will be shown in this paper.
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Document ID:
25943AA7
Measurement Scene Investigations
Author(s): Chris Spriggs
Abstract/Introduction:
Oklahoma Natural Gas Company, one of three companies that make up the Distribution Division of ONEOK, Inc., provides natural gas distribution services to 80% of Oklahoma or approximately 850,000 total customers. This customer base includes service to more than 50,000 commercial and industrial customers. Many of these commercial and industrial customers now have the opportunity to buy their gas on the open market. Oklahoma Natural Gas currently allows any customer, (other than residential), that uses over 1,000 Dth/year to be eligible to participate in our gas transportation program. At this time about 5,000 customers participate. In the future, the company is considering the expansion of this opportunity to all customers.
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Document ID:
9806FB12
About Ishm 2009
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:
DF193C24