About Ishm 2007
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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8F08080A
Basics Of High Pressure Measuring And Regulating Station Design
Author(s): E. D. Rusty Woomer, Jr., Pe
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. At a very high level, a good design engineer will focus on three generalities. First, the station must be designed with safety in mind, regarding both personnel and eq
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Document ID:
2DE3134F
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 meet stringent fiscal requirements. It is particularly difficult to measure complex fluid mixtures that are exposed to: (1) a range of operating conditions, (2) dynamic flow and fluid property behavior, and (3) changing equipment conditions. The compressibility factor is a ubiquitous concept in measurement. It arises in many industry practices and standards. Unfortunately the mathematical methods and data associated with it obscure some of the basic ideas behind it. The purpose of this paper is to provide background and insight into the development of compressibility factor methods, discuss its development and use in natural gas measurement, provide examples of the behavior of the compressibility factor over a broad range of conditions, and illustrate the level of uncertainty that compressibility standards provide.
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Document ID:
42FE9168
Coping With Changing Flow Requirements At Exsisting Metering Stations
Author(s): James m. Doyle
Abstract/Introduction:
In todays competitive gas market, utility companies must meet aggressive market strategies or suffer the consequences. All industries have cash registers, and gas distribution is no exception. Our measuring stations are our cash register. The problem is, these stations were designed 10, 20, 30 or even 50 years ago, and are now performing tasks they were not designed for. Therefore, changes must be made. Measurement personnel today must be trained and taught to cope with changing flow requirements. But, modifying a station to meet todays aggressive market can be very expensive. Equipment, such as regulators and the primary element (the meter tube, the orifice plate holder, and the orifice plate), must meet A.G.A. 3 requirements. The secondary element (the recording device) can raise expenditures significantly. Sometimes modifications cannot be made to deliver the specified volume of product needed, and replacement of a complete station is even more expensive. Companies today must watch money closely, and work to reduce operating and maintenance costs. To handle these situations effectively, technicians must be trained and taught to cope with changing flow requirements. Knowing your stations and their characteristics are an absolute. Technicians must become familiar with the kind of equipment their station has, and its proper use. The goal here is to detail the appropriate methods and equipment required to handle these tasks.
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Document ID:
FEE46543
Design Of Distribution Metering And Regulating Stations
Author(s): Edgar Eddy() Wallace Collins Jr
Abstract/Introduction:
The design of natural gas distribution metering and/or regulating stations is a mixture of science and art, or knowledge and judgment. The process requires four areas of knowledge: product, application, components, and communication. The goal in design is to use judgment to select and combine compatible components to create an effective, safe, and economical unit.
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Document ID:
56E2D983
Determination Of Leakage And Unaccounted For Gas - Transmission
Author(s): Lonnie Grady
Abstract/Introduction:
Natural gas transmission companies have evolved in the last forty years. Transmission companies would buy gas at the well head and sell gas at the burner tip. The business was straight forward and simple. Now, most transmission companies are transporters of gas. Other companies buy and sell gas while transmission companies haul it from point A to point B.
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Document ID:
13B63A09
Effects Of Abnormal Conditions On Accuracy Of Orifice Measurement
Author(s): Mr. 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:
2915040C
Fundamentals Of Gas Measurement
Author(s): Douglas E. Dodds
Abstract/Introduction:
To truly understand gas measurement, a person must understand gas measurement fundamentals. This includes the units of measurement, the behavior of the gas molecule, the property of gases, the gas laws, and the methods and means of measuring gas. Since the quality of gas is often the responsibility of the gas measurement technician, it is important that they have an understanding of natural gas chemistry.
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Document ID:
6A6B45B1
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. Below are listed some of the most commonly used terms and their definitions along with some examples of various conversions that must be made from time to time by people working in the natural gas industry:
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Document ID:
AE46A309
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:
D0D46D59
Fundamentals Of Gas Turbine Meters
Author(s): John A. Gorham
Abstract/Introduction:
The majority of all gas measurement used in the world today is performed by two basic types of meters, positive displacement and inferential. Positive displacement meters, consisting mainly of diaphragm and rotary style devices, generally account for lower volume measurement. Orifice, ultrasonic and turbine meters are the three main inferential class meters used for large volume measurement today. Turbines are typically considered to be a repeatable device used for accurate measurement over large and varying pressures and flow rates. They are found in a wide array of elevated pressure applications ranging from atmospheric conditions to 1440 psig. Turbine meters have also become established as master or reference meters used in secondary calibration systems such as transfer provers. A significant number of both mechanical and electrical outputs and configurations have become available over the past 50 years of production.
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Document ID:
5E90250B
Fundamentals Of Orifice Meter Chart Recorders
Author(s): David E. Pulley
Abstract/Introduction:
What is an orifice meter? The answer usually depends upon whom you are talking to. The term orifice meter is used to mean every thing from the orifice meter chart recorder to the entire meter station. American Gas Association defines the orifice meter as the complete measuring unit comprised of primary and secondary elements. The primary element consists of an orifice meter tube constructed to meet the minimum recommended specifications of the measurement authority contractually agreed upon by two or more parties. The secondary element consists of equipment that will receive values produced at the primary element. The values may be measured and recorded onto circular charts or received by electronic flow computers that calculate a volume onsite, to be retrieved as desired. In this paper I will address the Orifice Meter Chart Recorder and endeavor to explain its fundamental workings.
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Document ID:
C87E6999
Low Pressure Gas Measurement Using Ultrasonic Technology
Author(s): Daniel J. Rudroff
Abstract/Introduction:
With the increased use of natural gas as a fuel, higher natural gas prices, and new federal regulations, all buyers and sellers of natural gas are looking at ways to improve their natural gas measurement and reduce maintenance and the unaccounted for natural gas.
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Document ID:
49FBCB50
Mass Meters For Gas Measurement
Author(s): Karl Stappert
Abstract/Introduction:
Coriolis meters have gained worldwide acceptance in liquid applications since the early 1980s with an installed base of more than 400,000 units. Newer designs have increased low-flow sensitivity, lowered pressure drop, and increased noise immunity enabling performance characteristics that are similar or better than traditional metering technologies. Coriolis also has attributes that no other fluid measurement technology can achieve. Some of these attributes are the meters immunity to flow disturbances, fluid compositional change, and it contains no wearing parts. With more than 25,000 meters measuring gas phase fluids around the world, many national and international measurement organizations are investigating and writing industry reports and measurement standards for the technology. In December of 2003 the American Gas Association and the American Petroleum Institute co-published AGA Report Number 11 and API Manual Petroleum Measurement Standards Chapter 14.9, Measurement of Natural Gas by Coriolis Meter
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Document ID:
EF0DC0C7
Orifice Fittings And Meter Tubes
Author(s): Mitch Gardner
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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D2B80ADC
Orifice Meter Maintenance And Operation
Author(s): Scott Smith
Abstract/Introduction:
The world population is increasing and with this the energy demands in the world are also increasing. The increase in demand for electricity has made the natural gas industry more valuable than ever before. The natural gas industry like many other industries purchases, processes, and sells a commodity. For the industry to profit from the sale of this commodity an accurate measurement of the amount purchased and sold must be obtained. The Orifice Meter The orifice meter is a widely used method of natural gas measurement consisting of the primary element and the secondary element.
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Document ID:
DFEBB1A3
Problems Unique In Offshore Gas Measurement
Author(s): David Wofford
Abstract/Introduction:
First, we need to clear up a few common misperceptions. Measurement is Measurement is Measurement. Natural gas compounds dont think, metering and analytical systems dont care whether they are over water or dirt, and measurement standards are not only relevant to specific time zones. These are not intellectual beings that choose to exhibit behaviors based upon geography, culture, socioeconomics, political doctrine or the pursuit of spiritual fulfillment. Hydrocarbons are Hydrocarbons, Meters are Meters and Standards are Standards. Natural gas behaviors are defined within the laws of chemistry and physics. When hydrocarbons are extracted from the Earth, heated, cooled, filtered, swirled, separated, condensed, compressed, expanded, processed, refined, transported via a pipeline and quantified by a metering system, the hydrocarbon compounds dont care whether they are in the snow covered Rockies, windy West Texas, sunny Southern California or a hundred miles out to sea in the Gulf of Mexico. Hydrocarbon behaviors are non-discriminatory just equal opportunity combustible molecular structures seeking physical equilibrium in a man made world of cylindrical manipulation and containment. Now that weve cleared that up, what is so unique about offshore measurement problems? Well, from the quantitative and qualitative determination perspective, nothing really! The measurement problems are the same. (See previous discussion regarding the lack of cognitive subjectivity in hydrocarbon compounds) Multiphase fluids, swirling and turbulent flows, free liquids, poor system design, and primary, secondary and tertiary measurement element errors and uncertainties, to name a few, are common measurement problems experienced everywhere, regardless of locale. What is unique are the operational environment and constraints in comparison with typical onshore hydrocarbon pipeline, measurement and control facilities. The unique environment and constraints experienced offshore result in the necessity to give special consideration regarding the differences required for system design and facility operations, transportation, safety and training. These are the unique aspects of offshore measurement that will be addressed
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Document ID:
E438105E
Thermometry In Gas Measurement
Author(s): Stephen T. Stark
Abstract/Introduction:
The measurement of gas temperature is not easy. In fact, temperature is one of the more difficult variables to measure correctly any given quantity of natural gas changes temperature many times as it flows from one meter to another, all the way from the wellhead to its final destination. When natural gas is compressed, it heats up when it expands, such as after flowing through a regulator, control valve, or other restriction, it cools down. Natural gas temperature is also affected by the temperature of the pipe through which it flows.
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Document ID:
549867F0
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 subject is quite large and encompasses many different concepts, meter types and opinions, with new ideas being brought to the fore each year that the subject is reviewed. This paper will discuss the phenomenon of wet gas and the various types of meters that may be used for its measurement, together with some of the current thinking and concepts associated with wet gas measurement, a mention of some of the terms and mathematical concepts used to enable the reader to grasp a better understanding of what this stuff is about! Proprietary algorithms to determine liquid loading will not be mentioned
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Document ID:
DDC4E6FB
Contaminant Accumulation Effect On Gas Ultrasonic Flow Meters
Author(s): Jeff Gorman
Abstract/Introduction:
During a standard ultrasonic meter calibration as a flow laboratory testing facility, variances with the error percentages were noticed. Upon further inspection, an accumulation of a waxy substance had coated the internal diameter of the meter tube, flow conditioner and ultrasonic meter transducers. This paper discusses the problems associated with contamination accumulations and presents the data gathered from the initial test versus the final test and calibration after the meter tube assembly had been cleaned. Introduction: Being a natural gas transportation company presents many challenges in measurement. One very specific opportunity is to keep up with changing technology as new and improved forms immerge impacting how we do business. One of these newer technologies is the ultrasonic meter used in natural gas flow measurement for check metering and custody transfer. Following the publication of AGAs Report #9, Measurement of Gas by Multipath Ultrasonic Meters (Ref #1) in June of 1998 the popularity of these meters has greatly increased. There are many benefits of the ultrasonic meter over other traditional technologies greatly increasing their popularity in the market place. Body: One of the greatest benefits of the ultrasonic meter has been their stated performance in less than ideal service. Within todays natural gas transportation industry we all like to think that we have clean gas, free from contaminants, entrained inside the meter. However, the impact of the contaminants on the ultrasonic meters performance is said to be less than that of traditional meters. There have been many different tests performed in the past on other styles of meters, such as orifice and turbine meters testing performance and their accuracy in various service conditions. These tests illustrated how the meters accuracy was affected by the build up of contaminants on the internal surfaces of these meters. Some data has been published demonstrating the effect of contaminants on the larger size meters, 10 inch and above (Ref #2), however little is known about the effects on the newer smaller diameter meters such as a 3 unit. This paper will discuss the data from the verification and calibration tests for a major natural gas transports company comparing clean ultrasonic meters accuracy versus dirty ultrasonic meters accuracy as well as a discussion on smaller diameter ultrasonic meter with contaminant build up versus a smaller diameter. These discussions are important as ultrasonic meter manufacturers introduce small and smaller diameter meters into the market place, especially concerning custody transfer applications. Therefore, a discussion of recent testing is warranted.
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Document ID:
31501066
Application Of Densitometers To Liquid Measurement
Author(s): Gary Rothrock
Abstract/Introduction:
What is density measurement? How is it used? What determines good density measurement? The measurement of density is required in many applications in the hydrocarbon industry for both mass and volume flow measurement, interface detection, quality control, and concentration measurement. Technology today offers density measurement from a densitometer as a single measurement device to a Coriolis meter that will provide both density and flow measurement. This paper will discuss density terminology that differs by application, the factors that determine good density measurement, and will look at a variety of uses for a densitometer in the hydrocarbon industry.
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Document ID:
AEB3D330
Application Of Turbine Meters In Liquid Measurement
Author(s): James H. Smith
Abstract/Introduction:
Turbine meters have been used for the custody transfer of refined petroleum products and light crude oils for over 36 years. When correctly applied, they offer high accuracy and long service life over a wide range of products and operating conditions. Traditionally, turbine meters were used for the measurement of low viscosity liquids and PD meters for higher viscosities. However, recent developments in turbine meter technology are pushing these application limits while increasing reliability and accuracy. This paper will examine the application of conventional and helical turbine meters for liquid petroleum measurement
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Document ID:
8874EC3D
Automated Truck Loading Systems
Author(s): Shoyeb Hasanali
Abstract/Introduction:
Function of bulk marketing storage facilities known as distribution terminals, is to facilitate distribution of liquid products from storage to trucks (also railcars, barges, pipeline). Safety, Security, measurement accuracy, regulatory and reporting requirements are the key driving force in automation of loading terminals. Over the years due to EPA regulations and cleaner fuel acts it has become essential to mix products for making, as an example, mid-grade fuel. Fuel additization became essential where a small percentage of additive had to be added to fuel. For terminal efficiency and cost it became essential to come up with techniques to blend products at the loading rack instead of having to store in tanks. Also it would make more sense to inject additive into the product stream as opposed to physically add additive into compartment at end of load. An integrated blending and additizing control system in terminals became essential not only for realizing efficiency, but also have a system that is configurable and can adapt to blending ratio changes additive percentages adjustments and accurate mixing to obtain on specs. final product for distribution. Integration of modules such as tank levels and inventory, terminal and loading gantry secured access, safety circuit monitoring and transaction management became essential to centralize the overall terminal operation. Blending products such as gasoline, diesel and fuel oils with variable percentages have become a common place for formulating gasoline to cater to different commercial and industrial needs. In the recent years due to increase in crude oil prices and dependency on foreign oil, ethanol blending is becoming common. Ethanol is produced off corn and soybean and reduces overall gasoline contents. A 10% mix of ethanol in products is becoming a common at the gas pumps. Due to increase in cost of running and maintaining terminals many terminal operating companies are consolidating terminals and operating as joint venture terminals. To cater to the demand, terminals have to be efficient and have to remain open more than a single 8 hour shift, in some cases open 24/7. Automation allows terminal to operate un-manned during non-business hours.
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Document ID:
A8DBDC13
Calculation Of Liquid Petroleum Quantities
Author(s): Peter W Kosewicz
Abstract/Introduction:
must be determined. These elements are the quantity and quality of the hydrocarbon in question. This paper will address one of those elements, the determination of the quantity of the hydrocarbon in the transaction. The determination of the quantity of hydrocarbon can be further subdivided into: Static quantity determination and Dynamic quantity determination Static quantity is determined when the hydrocarbon is measured under non-flowing conditions, such as when contained in a tank, rail car, truck or vessel. Conversely Dynamic quantity determination occurs when the hydrocarbon is measured under flowing conditions. This paper will address the calculation procedures for petroleum quantities under flowing and non-flowing conditions. The same attention to detail and precision used in determining the primary measurement values (such as temperature and pressure) must be applied to the calculation procedures to maintain the same level of precision. The petroleum industry has developed standardized calculation methods, which are expressed in the API Manual of Petroleum Measurement Standards.
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Document ID:
A00D9301
Calibration Of Storage Tanks
Author(s): Michael Yeandle
Abstract/Introduction:
This paper will discuss several field measurement methods that are presently in use to calibrate upright, above ground, cylindrical, cone and floating roof steel storage tanks
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Document ID:
DE79D6D4
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
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Document ID:
2E944D42
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:
BD0C5FD0
Design, Operation & Maintenance Of L.A.C.T. Units
Author(s): Glen E. Meador, Ken Steward
Abstract/Introduction:
The two most common methods of measuring the volume of petroleum liquids are tank gauging and liquid metering. The problems associated with tank gauging are (1) it requires that an operator make an accurate liquid level determination by climbing to the top of the tank to be gauged, (2) that an operator make an accurate average liquid temperature determination, (3) that an operator make an accurate sediment and water content analysis and (4) that the tank be static, which means that no liquid can enter or leave the tank during gauging. Once the contents of the tank are removed, it is necessary to regauge the tank. Since crude oil is sold on the basis of temperature, API Gravity and the amount of Basic Sediment and Waste (BS&W), it is very important to make accurate measurements. The greatest effect on volume is temperature - typical crude oil will expand and contract at the rate of 2% per 40 F temperature change. The accumulation of errors present in the tank gauging may be as high as 1%. The potential annual losses in revenue, based on daily lease production and on 60.00 per barrel oil
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Document ID:
5559556D
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:
FA5139C6
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:
DC1168A8
Effects Of Flow Conditioning On Liquid Measurement
Author(s): Philip D Baker
Abstract/Introduction:
The main objective of this paper is to provide a summary to-date of the API Liquid Turbine Meter Flow Conditioning Research Project. Insight is provided into the effects on liquid turbine meter accuracy of flow disturbances, caused by debris on strainer screens, for various upstream piping geometries and different types of flow conditioners. This research program was initiated by the API Committee on Liquid Measurement (COLM) in 2005, and continued during 2006, primarily because of several different field observations that sometimes debris on a strainer screen can cause a significant shift in the meter factor (MF) of turbine meters, which is eliminated when the debris is removed from the strainer. Turbine meter MF shifts of up to 0.25% have been observed in the field due to debris on the strainer screen, when using tube bundle type flow conditioners. The main objectives of the laboratory research program were to: (1) Try to duplicate in the laboratory the problem observed in the field (described below), using conventional tube bundle type flow conditioners, (2) determine if the new isolating and/or high performance type flow conditioners eliminated, or substantially reduced, the problem, (3) determine the magnitude of MF shift when using just 20 diameters (20D) of straight pipe as a flow conditioner, (4) determine if different meter run inlet piping geometries (i.e., a single horizontal elbow, three elbows out-ofplane and two vertical elbows in-plane) have an effect on the MF shifts obtained using the various type flow conditioners, (5) determine if different type turbine meters are affected differently by a given flow disturbance, and (6) determine if the magnitude of the meter factor shift is affected by the size of the strainer.
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Document ID:
73EE5CC0
Effects Of Petroleum Properties On Pipeline Measurement
Author(s): James E. Gallagher
Abstract/Introduction:
marketers, governmental authorities and the general public. In fact, accurate measurement of hydrocarbon fluids has a high impact on the Gross National Product of exporting and importing countries, the financial performance and asset base of global companies, and the perceived efficiency of operating facilities. An understanding of the process (operating and fluid) conditions, as well as, the physical properties of the hydrocarbon fluids are fundamentally important before designing or analyzing these measurement facilities. For simplicity, we will limit our treatise to dynamic measurement applications. Several methods and types of equipment are utilized to achieve accurate measurement. The basic measurement process remains the same --- the act of comparing a known mass quantity to an unknown mass quantity.
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Document ID:
1FBD6A81
Polymer-Grade Ethylene Measurement
Author(s): James E. Gallagher
Abstract/Introduction:
An ethylene transportation system consists of a pipeline network and salt dome storage facility linking producers and consumers. Since producers and consumers are not equipped with on site storage, the systems are designed with maximum flexibility to satisfy the continually changing demands of the operations (Figure 1). Ethylene pipeline and storage systems are operated in either the gaseous or dense phase fluid region. Systems designed prior to the mid 1970s were designed to operate in the gaseous fluid region and comply with DOT regulations for gas pipelines. Systems designed over the last two decades were designed to operate in the dense phase region for several reasons - lower transportation cost, lower metering cost and compliance with the DOT HVL regulations. Polymer-grade ethylene transportation systems are designed to operate over the following dense phase fluid range - 900 - 2160 psig 35 - 120 deg. F
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Document ID:
5BADB3C4
Evaporation Loss Measurement For Storage Tanks
Author(s): Warren A. Parr, Jr.
Abstract/Introduction:
In the 1950s hydrocarbon evaporation loss from storage tanks was studied to develop emission estimating equations. At that time, the primary driver for knowing the evaporation rate was system loss control. During the early 1990s, the US Environmental Protection Agency (EPA) began programs for stricter record keeping and reduction of storage tank emission. This forced industry to scrutinize the accuracy of existing evaporation loss estimating equations and to develop improvements to various tank appurtenances in an effort to lower hydrocarbons emissions. Much of the EPA activity was focused on floating roof tanks. This paper will review: Sources of emissions from floating roof tanks Research and development to improve emission loss equations Testing of existing fittings Testing of design improvements to lower emissions Development of EPA approved test protocol for improved equipment designs Future areas of emission research in floating roof tanks In order to help the reader follow the organization and sequence of events of this paper, the major topics listed above will be listed in bold underlined capital print. The subsections within each major section will be in capital print only.
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Document ID:
E5FBF46F
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. Proper procedures could implement this process: 1. What is the Composition or Fluid to be measured? a. Crude Oil b. Light Liquid Hydrocarbon - Condensate - Natural Gas Liquids c. Pure Product i. Propane ii. Butane d. Refined Product 2. What is the operating Pressure and Temperature? 3. How does the operating Pressure and Temperature affect: a. Density b. Expansion/Contraction Characteristics c. Viscosity d. Vapor Pressure 4. What other operational factors affect proper measurement? a. Basic Sediment and Water 5. Based on the answers to the previous questions, what is the best equipment to handle the product? 6. What types of calculations will be implemented to correct the volume, or mass, measured at process conditions to the standard conditions
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Document ID:
483AF7C6
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:
0243C5EA
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:
7B38DA50
Gauging, Testing And Running Of Lease Tanks
Author(s): Mike Lanning
Abstract/Introduction:
Gauging is a measurement procedure whereby the QUANTITY and QUALITY of the crude oil are determined at the point of sale by a company gauger or other designated representative, such as a Crude Transport Driver. Typically, we think of lease tanks as having volumes of 1,000 barrels or less. The gauger is primarily responsible for rejecting non-merchantable crude oil and buying accurate volumes of merchantable crude oil that can be refined, traded, or sold. His company is fully dependent upon his competence and sound judgment, while requiring him to be conscientious, accurate, professional, and courteous.
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Document ID:
900C2433
Helical Turbine Meters For Liquid Measurement
Author(s): Glen Wilson
Abstract/Introduction:
The oil industry has used conventional turbine meters and positive displacement (PD) meters in the custody transfer measurement (CTM) of crude oil and refined products for more than 6 decades. The choice of which meter to use depends on the product being measured, technical parameters of the application, total cost of meter ownership, and the accuracy required. Conventional turbine meters have typically been used in low viscosity refined products, with limited use in moderate to high viscosity crude oil due to performance limitations. The capillary seal positive displacement meter has been the choice for custody transfer measurement of moderate to high viscosity crude oil, providing good measurement but at a high total cost of ownership. Today, a new iteration of the turbine flowmeter is available to meet the necessity for accurate CTM in either a single product or a multiple products application, performing within the API guidelines for CTM at the measurement site. The Dual Bladed Helical Turbine Meter is designed for the measurement applications which have typically been divided between conventional turbine meters and positive displacement meters. This uniquely designed turbine flow meter provides highly accurate custody transfer measurement in applications ranging from very low viscosity products such as LPGs, to heavy crude oil (standard applications to 500 cSt., special applications to 1000 cSt)
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Document ID:
08D1555F
Installation And Operation Of Densitometers
Author(s): Don Sextro
Abstract/Introduction:
A densitometer is an on-line and continuous device used to measure the density of a flowing stream. In the oil and gas industry, a densitometer is normally used to measure the density of liquid hydrocarbon finished products like propane and gasoline and liquid mixtures like Y-grade natural gas liquids (NGL), but can also be used to measure the density of crude oil. The typical installation is in a single-phase liquid stream, but densitometers can be used to measure single-phase gas or vapor. This paper addresses only continuous, on-line liquid density measurement. There are a number of applications in the oil and gas industry where measured density is important. First, and probably the most widely used, is to determine the quantity of material passing through a meter. The quantity may be determined either through mass or volumetric measurement techniques, each using the measured density but applying it to the final quantity in a different way. A second use is to detect a pipeline interface, the plug of liquid between two dissimilar products shipped in the same pipeline. Continuous, on-line density measurement provides a pipeline operator with the ability to see the density change from one batch to the next and make the appropriate valve changes to properly route liquids to the correct destination. Another common use is in pipeline leak detection where operators look for relatively small leaks by comparing pressures and flow rates at points along a pipeline. Measured density can provide a more accurate prediction of frictional pressure loss in the pipeline since, in addition to flow rate, pressure loss is a function of the Reynolds number which is in turn a function of the fluid density. Lastly, measured density can also provide meaningful data for quality monitoring of finished products and other fluids. This paper focuses on installing and operating densitometers in dynamic systems used to measure quantities of material passing through a meter from the perspective of custody transfer. Principles detailed in this paper can be applied to installing and operating densitometers for interface, leak detection or quality monitoring services
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Document ID:
8EE8C4AE
Liquid Measurement Field Surveys
Author(s): C. Stewart Ash, P.E.
Abstract/Introduction:
What is a Liquid Measurement Field Survey? Isnt that just another name for an Audit? In the Oil Industry, the two are often considered to be the same. There are indeed similarities between the two, but there are also distinct differences. An Audit is usually conducted by an Auditor either from the corporate internal audit group or from an external independent auditing company. This type of audit is an official examination and verification of accounts and records to assure that adequate control is provided for company assets. It is a review to assure that established procedures are followed, calculations are done correctly, and the accounting process is correct and current. A Measurement Survey is a review of field facilities and operations usually conducted by either in-house measurement specialists or qualified outside consultants. The purpose of the survey or review is to ensure the proper equipment is used, the equipment is installed in accordance with the manufacturers and/or industry guidelines, proper measurement procedures are followed, and personnel are properly trained. One of the major differences between the two is that the Audit verifies that the established procedures are being followed, while the Measurement Survey verifies the procedures are indeed the correct procedures for the specific task, not just are they being followed. This paper will cover some of the points that should be included in a Measurement Survey. A checklist that can be utilized during a survey is included at the end of the paper. Audits are discussed in ISHM Class 7050 Auditing Liquid Measurement and ISHM Class 7040 Auditing Gas Measurement and Accounting Systems.
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Document ID:
E3FFDD3D
Liquid Measurement Station Design
Author(s): Bruce Byers
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 including a user-friendly, man-machine interface that effectively manages the flow measurement and control requirements. The task of the station or system designer is to transform these requirements into engineering specifications, drawings, and bills of material for procurement, manufacture, test certification and delivery to the end user of a multitude of components specifically selected and integrated 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:
6DE582C4
Marine Crude Oil Terminal Measurement Systems
Author(s): Harold E. Osborn
Abstract/Introduction:
In this paper we will discuss the different types of measurement systems used at crude oil terminals, the requirements of these systems and why they are important.
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Document ID:
56B91E7C
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:
956C87A0
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:
0A448D0F
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:
0D0B71A6
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. In liquid petroleum blending however, the result has always been shrinkage. In this paper, only the negative deviations or losses will be addressed.
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Document ID:
5A541235
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:
A22CBBF9
Orifice Meters For Liquid Measurement
Author(s): Fred Van Orsdol
Abstract/Introduction:
Orifice meters have been in common use for many decades, but in the energy industry their use has been primarily in gas metering systems. This is interesting, in that much of the research to develop orifice meter factors (discharge coefficients) has been performed using oil, water, steam and air, as well as natural gas. Orifice meters used in liquid measurement provide good accuracy without the requirement for meter proving as long as they are properly designed, installed, calibrated and maintained. If higher levels of accuracy or wanted, they can be proven using appropriate software and hardware and traditional meter proving systems
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Document ID:
0FBC2399
Pycnometer Installation, Operation And Calibration
Author(s): Harold L. Gray
Abstract/Introduction:
The process of installing Pycnometers for the purpose of calibrating a density meter. The process of field verifying pycnometer calibrations. Experiences in verifying flow through the pycnometer and ways of achieving temperature equalization in both the density meter and the pycnometers.
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Document ID:
FEBDA348
Resolving Liquid Measurement Differences
Author(s): Herbert H. Garland
Abstract/Introduction:
What is a custody transfer? It is the volume of liquid moved multiplied by the tariff, which equates to ! It is the bottom line, which is the cash register. Is your companys cash register running over or short? What is the percentage it is off? To minimize liquid measurement problems, clear lines AUTHORITY and RESPONSIBILITY must be established and accepted. Established by management and accepted by the employee(s) assigned this role. To adequately perform loss/gain tracking and analysis you must be able to RECOGNIZE that a problem exists. More often than not we tend to think it is the other person or company that has the problem. It is a matter of admitting you may have the problem instead of the others. Check your equipment and procedures first. DETERMINE what is causing the problem. Is it an error in procedure, equipment failure, malfunction or a calibration problem? Or is it human error? When this has been determined, you can then CORRECT the problem. To assist in accomplishing this, you need to consider training and developing field personnel in measurement control practices. Then you must support them with expertise in API Manual of Petroleum Measurement Standards (MPMS) and corporate practices and policy. You should also ensure the most effective technologies are used and remain aware of philosophical industry trends.
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Document ID:
6AF390E0
Troubleshooting Liquid Pipeline Losses And Gains
Author(s): Joseph T. Rasmussen, Michael R. Plasczyk
Abstract/Introduction:
Todays pipelines are multi-dimensional systems providing multiple services for many shippers and customers. Pipeline systems may connect multiple origins and destinations, and carry various products across long distances with changing profiles, pipe dimensions and directions. Monitoring pipeline gains and losses employs tools and analysis methods developed specifically to troubleshoot pipeline variances. Examination of pipeline gains and losses uses some basic statistical tools as well as intuitive and creative insight into what controls gains and losses. The basic tool for evaluating system performance is Loss/Gain which is a measure of how well receipts, deliveries and inventory match up over a period of time. The concept is similar to that used for leak detection, but usually covers a longer time period than does leak detection. Loss/gain is a measure of the quality of the overall measurement in a system, and excessive loss/gain can signal the need for an investigation to identify causes and possible corrective actions. Good measurement can be assured by continuous monitoring to determine if systems, equipment and procedures are operating within acceptable limits. This may be done by the use of Control Charts. This paper reviews control charts and other charts which may be used to monitor systems and offers troubleshooting guides to use when a pipeline system is out of balance
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Document ID:
09C1BB42
Liquid Ultrasonic Flow Measurement 2007
Author(s): Herb Decker
Abstract/Introduction:
Abstract & Opening Liquid ultrasonic flow meters have been around for forty plus years but it wasnt until the release of custody transfer meters and industry standards that the end user communitys interest began to grow. Non moving part technology presents some challenges to the end users regarding how to apply them, results to expect and how to prove them. This paper will explore these issues and offer guidance based on the authors experience in flow measurement of hydrocarbons using this technology.
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Document ID:
6A97C97A
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:
5C8E4821
Measuring High Viscosity Liquids With Flow Meters
Author(s): Peter P. Jakubenas
Abstract/Introduction:
This paper will discuss effective methods for measuring high viscosity liquids with various types of flow meters
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Document ID:
0CA61AFE
Proving Liquid Meters With Microprocessor Based Pulse Outputs
Author(s): Don Augenstein,Matt Mihalcin
Abstract/Introduction:
Is there a fundamental issue with regard to the operation of Coriolis flowmeters and Ultrasonic transit-time flow meters such that proving them is difficult or impossible for certain applications? Experience certainly has shown that some applications of these meters has made the proving experience range from plain difficult to outright frustrating. This paper explains why some applications of these meters provide poor proving performance. Specifically, this paper discusses how these meters sample the flow rate and how they process the flow rate output. This paper details the fundamental sampling issue with these meters and provides thoughts on guidelines as to how to properly apply these meters with field provers. This paper does not discuss the physical explanation on the measurement statistics of either technology - but leaves that to other papers (such as Class 2430). These newer technologies use microprocessors to control their electronics, to communicate diagnostics, to sample their respective sensors, to compute the flow and to output volume/mass pulses. Because of this common dependence on the microprocessor, these two technologies, the UFM and Coriolis meters, will be collectively referred to as microprocessor based meters (MBM) - to emphasize this common design characteristic.
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Document ID:
8C154F46
Proving Liquid Ultrasonic Flow Meters
Author(s): Don Augenstein
Abstract/Introduction:
Ultrasonic transit-time flow meter (UFM) technology is now well over 50 years old. UFM improvements in transducer design, signal processing and more importantly, the understanding of factors that influence the performance of these meters have greatly improved these meters performance. Current UFMs achieve accuracy and reliability comparable to or better than older mechanical technologies (i.e., turbine and positive displacement meters) and are now beginning to displace these traditional flow meters in hydrocarbon measurement applications. This transition is being driven by a number of UFM attributes including: High accuracy and high turndown ratio Availability of large size meters Non-intrusiveness Low maintenance costs Information on flow characteristics and fluid properties Excellent on-line diagnostics But, unlike many mechanical meters, UFMs have had more difficulty in proving according to API Chapter 4.8. The difference in proving performance is understood when the physical differences between mechanical meters and UFMs are considered. With mechanical meters, the flow through the device is controlled by either turbine blades or by other positive displacement mechanisms. However, with the UFM, the flow is only measured as it passes through the meter in most cases without any interference from the meter itself. Since the UFM does not control the fluid motion, there will be flow variability that the UFM must average out. As a result, UFMs will have more difficulty in proving according to API Chapter 4.8.
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Document ID:
2D4C7AD2
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:
068EC922
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 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 deepwater 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:
9B2C6BEE
Application Of Flow Computers For Gas Measurement And Control
Author(s): Carvel Jasmin
Abstract/Introduction:
Flow computers are microprocessor controlled CPUs specifically designed to measure and regulate the transfer of a fluid from one point to another. They are an essential part of electronic fluid flow measurement, and are usually installed in various remote locations throughout the production, transmission and distribution segments of the gas industry. The function of a flow computer is fourfold: collect measurement data, calculate and store measurement data, transmit stored measurement data to a host system, and execute control requirements. In addition to measurement data, the event log, audit trail, and alarm information is also collected, stored, and subsequently transmitted to a host system in accordance with API Ch 21.1 - Flow Measurement Using Electronic Metering Systems. All these flow computer functions are controlled by on-board firmware, sometimes in conjunction with inputs from the host system. It is this on-board firmware, and associated host software, that allows the user to maximize the flow computers versatility and efficiency
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Document ID:
3BDD516F
Applications Of Portable Computers And Software
Author(s): Trey Thee
Abstract/Introduction:
Laptops, handhelds, palmtops and PDAs are becoming common in the Natural Gas Industry to perform a variety of portable computing functions. Applying these different technologies to fit a given task is sometimes not immediately apparent. Portable Computers do make the field jobs easier to perform, if time is taken to assure that they are selected to fit the application. Emphasis in this paper will be on mobile computing as it relates to the Natural Gas Industry.
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Document ID:
61FAF337
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:
79520FDE
Basic Electronics For Field Measurement
Author(s): Dale Gary Edited
Abstract/Introduction:
This paper is written with the idea of presenting basic electronic principles and how to apply these to common applications in the oil and gas industry
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Document ID:
450A4F49
Scada Systems
Author(s): Richard Cline
Abstract/Introduction:
This paper will address concepts of SCADA (Supervisory Control and Data Acquisition Systems) and their application to the measurement industry. An important focus of the paper is to provide the reader with an understanding of the technology and with guidelines to be used to evaluate this equipment as part of an automation project.
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Document ID:
0ED32D47
Communication System For Gas Measurement Data
Author(s): Royce Miller
Abstract/Introduction:
Todays market offers a variety of communications systems ranging from simple to complex. Making the best choice can mean the difference between success and failure. This discussion will focus on the connectivity between the SCADA server (Master Terminal Unit), Remote Terminal Units (RTU), Electronic Flow Meter (EFM) and Programmable Logic Controller (PLC). Common practice is to remotely locate the SCADA server in a data center or business office. This location is usually located away from any production field or pipeline. This practice can create demands on connectivity options. Recurring cost must be controlled while providing the service that customers demand. Managing this connectivity must be well documented and maintained. This can be a difficult task when many locations are isolated in hard to reach locations. This task may seem impossible but the reality is that we dont have to choose a single option for all needs. In fact the more complex systems usually rely on numerous connectivity methods. Some of the options are described here. When choosing from the available options SCADA server connectivity must be considered. The options fall into 2 groups: circuit switched and networked. Broadband is generally desirable between the SCADA server and the production area but not usually required at the production field or pipeline, see the Typical SCADA Network Topology drawing below Fig #1. Dial up modems can be very costly and mainly used on small systems when the setup time for the modem/call is not critical. Monthly recurring cost and long distance/toll charges limit the usefulness of this option. Microwave and dedicated leased line are still options but economically not favorable. Dedicated T1, DSL, cable modem, satellite internet or wireless ISP and Ethernet radio offer benefits for the SCADA server.
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Document ID:
5247E7B1
Economics Of Electronic Gas Measurement
Author(s): Shawn Kriger
Abstract/Introduction:
Electronic flow meters (EFM) or chart recorders? Old technology or new? These are two basic questions energy companies must answer when planning the short and long term goals for the measurement and control of their production, gathering or transmission systems. Many companies have already made the switch to electronics. They are using EFMs on every new field installation. They are also in the process of replacing charts that already exist in the field. Other companies have not made the switch. Chart recorders continue to be the main component of their gas measurement systems. Back in the early 1980s, electronic flow meter technology was still relatively new to the gas industry. Chart recorders were the standard and many companies were skeptical of the new electronics technology. Over the past twenty five years, electronic technology has consistently become better and more reliable. Battery and solar panel technology has improved. Microprocessors are faster and more reliable. Flow meters continue to gain additional functionality, which enable operators to perform total well site automation all from the same device. And most important, cost of electronic technology continues to drop. This paper is targeted at companies that are currently analyzing their gas measurement systems and trying to decide whether there is an economic benefit of electronic flow meters vs. charts in the field. The intent is to analyze key areas which effect overall operations and provide examples of potential economic benefit or loss.
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Document ID:
32404B87
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:
F99D80EA
On-Line Flow Computers For Custody Transfer
Author(s): Rick Heuer
Abstract/Introduction:
In computer technology and telecommunication, on-line and off-line are defined by Federal Standard 1037C. They are states or conditions of a device or equipment or of a functional unit. To be considered on-line, a device must be at least one of: Under the direct control of another device Under the direct control of the system with which it is associated Available for immediate use on demand by the system without human intervention Connected to a system, and is in operation Functional and ready for service This was extracted from Wikipedia. An on-line dictionary!
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Document ID:
EB550325
Real Time Electronic Gas Measurement
Author(s): Don W. Griffies
Abstract/Introduction:
Methods of gas measurement have undergone tremendous change during the last couple of decades. Electronic measurement devices that are significantly more precise and contain manageable flow file databases are replacing mechanical dry-flow meters. This is commonly referred to as electronic flow measurement or EFM. In addition, these devices can communicate remotely utilizing radios, landline or cellular telephone, hard wire and / or satellite links. This type of communication is called telemetry. The final phase of the real-time measurement equation is the addition of on-line gas analysis data that allows the flow computer to compute its volumes utilizing this information.
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Document ID:
BCA1910F
Spread Spectrum Systems For Efm And Scada
Author(s): King Poon,Huichun Xing
Abstract/Introduction:
Communications is an important part of SCADA and EFM systems. Data, generated by the RTUs (remote terminal units) and flow computers, must be transferred from the field back to the host computer so it can be distributed and used by different parties. Various types of communication equipment systems are used in SCADA and EFM systems. This equipment consists of modems that interface to dial-up networks or leased lines, licensed radios, satellite, and microwave. Licensed radios are data radios that use dedicated frequencies to transmit data back and forth. This type of radio requires an FCC license to operate. As these licenses for dedicated frequencies become more difficult to obtain in the United States, spread spectrum radios are rapidly gaining popularity in SCADA and EFM networks.
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Document ID:
B4E3482C
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:
048AB627
Testing, Maintenance, And Operation Of Electronic Flow Computers For The Gas Industry
Author(s): Stephen T. Stark
Abstract/Introduction:
Natural gas flow computers have been in use since the middle 1960s, becoming much more practical with the development of improved microprocessors in the 1980s and later advancements in more reliable transducers (e.g., temperature, pressure, differential pressure, etc.). In the earlier stages of development, gas flow computers calculated flow - and did very little else. Today in 2007, flow computers systems do much more than just measure flow, performing many SCADA-related tasks that are necessary in todays modern gas industry. Even so, and in the context of this paper, we will focus on the gas measurement related issues only.
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Document ID:
91EA931E
Transient Lightning Protection For Electronic Measurement Devices
Author(s): Leon Black
Abstract/Introduction:
We have all heard of or seen the devastating effects of a direct lightning burst. Communication equipment destroyed. Transmitters and EFM devices vaporized into slag metal. Complete process and measurement systems down with extended recovery times. These effects are the most dramatic and the easiest to trace. However, these kinds of events are rare. The more prominent events are those that occur on a day-to-day basis without we, the user, even knowing. With the advent of the transistor and today when surface mount electronics is the norm and not the exception, transient suppression has become a science of necessity. Tight tolerances of voltage requirements and limited current carrying capabilities makes the new compact integrated circuits much more susceptible to many types of transients.
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Document ID:
5AA77005
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:
BF83097E
Design, Calibration And Operation Of Field Standard Test Measures
Author(s): William R Young Jr
Abstract/Introduction:
A field standard test measure is a graduated neck volumetric container, fabricated to stringent design criteria to deliver a specific volume of liquid when drained. To identify its true volume value, it is calibrated by an official agency such as the National Institute of Standards and Technology (NIST). The primary purpose of a field standard test measure is to provide a standardized volume, used for the calibration of displacement and tank provers, when calibrated by the waterdraw method. Field standard test measures are commonly referred to as test measures-for simplicity the term test measure or measures will be used in this paper for field standard test measures. Test measures can be either of the invertible or non-invertible (stationary bottom-drain type). Invertible measures are usually small measures of less than 10 gallons, while the non-invertible measures are mounted on legs and are typically greater than 10 gallons. They can also be classified by their graduated neck resolution. Test measures of the same volume can have either a normal or high sensitivity neck. Normal sensitivity measures have a larger neck diameter and therefore have less resolution on the scale. High sensitivity measures have a smaller diameter neck and have much greater resolution. Since the neck length gets much longer when its diameter is reduced, as the volume gets larger it becomes increasingly impractical to have a highly sensitive neck. Generally, measures of less than 100 gallons can have high sensitivity necks and not be too excessively tall.
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Document ID:
2E38334D
Effective Use Of 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:
35E39DC3
Flow Calibrating Ultrasonic Gas Meters
Author(s): Casey Hodges
Abstract/Introduction:
Ultrasonic metes are an increasingly important part of natural gas measurement. These meters have become highly sophisticated with many useful characteristics. Modern ultrasonic meters can give the user critical information about not only the flow, but the health of the meter. However, it is still of utmost importance that these meters be calibrated correctly and that the results of the calibration are applied correctly. This paper will cover the fundamentals of ultrasonic meter operation. Installations can affect the performance of the meter, and this will be discussed. The calibration of ultrasonic meters will also be explored. Finally, the paper will look at different methods for interpreting the results of calibration
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Document ID:
2B1179C6
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:
A4627CB9
Lact Unit Proving ? The Role Of The Witness
Author(s): Art Casias, Terry Ridley
Abstract/Introduction:
Witness, as defined by the New Webster?s Dictionary, 1.n, a person who has observed a certain event, the unwilling witness of a quarrel a person who testifies to this observation, esp. in a court of law, and esp. under oath a person who testifies to the genuineness of a signature on a document by signing his own name to the document an authentication of a fact, testimony public affirmation of the truths of a religious faith something taken as evidence, to bear witness to declare, on the strength of personal observation, that something is true to give as evidence, to bear witness, knowledge, testimony. The role of the witness, in the proving of a LACT unit, requires you to understand the operations of both the LACT and ACT units and the device used in proving their accuracy
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Document ID:
0EB89852
Liquid Flow Provers
Author(s): John Gradziel
Abstract/Introduction:
Mechanical Displacement Provers are the most commonly used and accepted method of meter proving. They are dynamic and provide NIST traceability. This paper discusses the design and general operation of Mechanical Displacement Provers in oilfield applications.
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Document ID:
FD5B7D0D
Liquid Meter Proving Techniques
Author(s): Dan Comstock
Abstract/Introduction:
Liquid Meter Proving is the physical testing of the performance of a meter, in a liquid service, that is measuring the flow or volume throughput. The meter proof or test, is performed by placing a meter in series with a meter prover, which has a known base volume at standard conditions, in such a way that during any given test run, all the product measured by the meter is also measured by the prover, and equally important, only the product measured by the meter is measured by the prover. Then the meter indication is compared to the known prover volume. Meters can provide more precise measurement of the liquids handled, if they are proved regularly and in actual operating conditions. A meter, which has been tested on a given product, with a given density and viscosity, at a given flow rate, temperature and pressure will need to be retested when any one of the above conditions change significantly.
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Document ID:
C0955043
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
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Document ID:
0EF54323
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:
B12A1ED9
Proving Coriolis Meters
Author(s): Marsha Yon
Abstract/Introduction:
Coriolis meters are in use throughout the hydrocarbon industry for the measurement of fluids including crude oil, products such as fuel oil, gasoline, and diesel, and light hydrocarbons such as natural gas liquids, propane, etc. When used for custody transfer, it is most often required by contract between the buyer and seller that the meter be proven in the field on the fluid that is being measured and at the conditions under which it will be operating. This paper will utilize the American Petroleum Institutes Manual of Petroleum Measurement Standards (MPMS) as the reference for industry practices for field proving methods and calculations. Coriolis meters can measure volume, mass and density. If the meter is used to measure volume and the pulse output represents volume, the meter should be proven as a volume meter. MPMS Chapter 4, Proving Systems, contains information specific to volumetric proving. If the meter is used to measure mass and the pulse output represents mass, the meter should be proven as a mass meter. Currently Chapter 4 does not contain information relative to proving on a mass basis however MPMS Chapter 5.6, Measurement of Liquid Hydrocarbons by Coriolis Meter, does provide guidelines for mass proving. If the density output is used for custody transfer flow calculations, the density measurement can be proven using MPMS Chapter 14.6, Continuous Density Measurement if a pycnometer is used or MPMS Chapter 9, Density Determination if a hydrometer is used. MPMS Chapter 12 Calculation of Petroleum Quantities addresses the calculation of a meter factor and the application of the factor to the flow calculation. The temperature output of a Coriolis meter if obtained from the internal RTD mounted on the sensor tube, is not recommended for use in custody transfer measurement as it is not intended to measure the fluid temperature but the temperature of the tube itself.
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Document ID:
07ADB0D5
Theory And Application Of Pulse Interpolation To Prover Systems
Author(s): Galen Cotton
Abstract/Introduction:
Here we take an in-depth look at the use of Pulse Interpolation as it applies to reduced volume provers (captured piston provers in current API parlance) and the danger implicit in relying on the technique where the fundamental conditions implicit in its use do not prevail. The application of API MPMS 4.8 Appendix A may be inappropriate for some measurement technologies
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Document ID:
471B6733
VERIFICATION/CERTIFICATION Of Devices Used In Liquid Measurement
Author(s): Anne Walker Brackett, Ph.D.
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:
921185A0
Witnessing Orifice Meter Calibrations And Field Testing
Author(s): Allen Chandler
Abstract/Introduction:
The need for witnessing gas measurement equipment testing has probably been around since the dawn of the gas custody transfer age. That is, where the gas is physically changing ownership from one entity to another. In the modern age, the old handshake is no longer the equivalent of a valid contract as it once was and rightfully so, each producer, transmission pipeline operator, distribution system owner or transportation broker is concerned that their product is bought and/or sold in as accurate an environment as is humanly possible. Modern day gas prices are volatile to say the least. The market bounces around on an almost daily basis and the price per thousand standard cubic foot of gas seems to steadily increase. Coupled with generally milder temperatures in many regions of the United States and the huge gas volumes that change hands daily, it becomes ever more critical that natural gas is measured with greater accuracy and a witness to the testing procedure is one more positive step toward that end.
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Document ID:
F772E8DC
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:
E7E8A502
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. For this reason 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:
05360618
Chromatographic Analysis Of Natural Gas Liquids
Author(s): Ronald E. Beaty
Abstract/Introduction:
Natural gas liquid laboratory surveys are conducted to assure that laboratories provide accurate component analyses. The procedure guarantees that the funds are exchanged on an equitable basis. The test procedure utilizes two or three analyses of two or three natural gas liquid samples that represent the range of components that would normally be found separated from the natural gas. Once properly conditioned, the samples are analyzed on a gas chromatograph used by the laboratory. The resulting mole percentages are compared for accuracy, and each chromatographs relative response factors are used for a plot to check the chromatographs detector linearity. The test methods and a critical review of practices and procedures can determine the ability of a laboratory to provide analyses GPA acceptable results.
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Document ID:
3D746C82
Crude Quality - What Is Involved And Why Is Quality Important
Author(s): D. Pat Morgan
Abstract/Introduction:
Crude Quality - What is Involved and why is Quality Important is a major issue in the petroleum industry today. A Crude Quality Oversight program is designed to monitor the ongoing quality of a crude supply by measuring certain key properties, which directly correlate to quality, value and performance. There are many benefits to this type of monitoring program
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Document ID:
9ED07603
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 that measurement and control of the concentration levels of this compound within natural gas pipelines. This paper will address the properties, purpose of measurement and measurement technologies for H2S and discuss how these technologies can be adapted to the measurement of Total Sulfurs in natural gas streams.
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Document ID:
E94DCEB0
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 Btu per cubic foot and containing some C4 thru C6+ components (butanes thru natural gasoline).
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Document ID:
42BED03E
D.O.T. Requirements For The Transportation Of Sample Cylinders
Author(s): David J. Fish
Abstract/Introduction:
The United States Department of Transportation (D.O.T.) is a department of the U.S. Federal Government which oversees all issues regarding transportation within the United States of America and U.S. Territories. Its influence around the world is great and widely respected, but its jurisdiction and power of enforcement is limited to the USA and its territories. As regards this paper, we will discuss the D.O.T. and its involvement surrounding sample cylinders for the hydrocarbon industry and the rules regarding the movement of these cylinders from point to point in the United States. The most important statement to be made is that the D.O.T. and Code of Federal Regulations, Title 49 (CFR-49) is the definitive and final authority on all issues regarding the handling and transportation of sample cylinders. Much has been written and quoted over the years and many regulations have changed over the years. It is the sole responsibility of each company involved with sample cylinders, to have a copy of CFR-49 and to be responsible for clarification of any issues they have, by researching CFR-49 and consulting with D.O.T. representatives. They have the final word on any questions. D.O.T. is the enforcement agency regarding sample cylinder transportation. The author of this paper and the company he represents do not present themselves as authorities on this matter for you or your company. This paper is presented for the sole purpose of providing limited information and to encourage you and your company to become better informed for your specific needs and operations.
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Document ID:
6F51A65A
Energy Measurement Using Flow Computers And Chromatography
Author(s): Burt Reed
Abstract/Introduction:
The means and methods of transfer of quantities of natural gas between buyers and sellers have been changing for many years. When coal gasification was used to fuel the streetlights in Atlanta, Ga. There was no reason to even measure the commodity. The municipality generated the gas, transported it, and burned it. When Frank Phillips started purchasing gas rights back in the 1930s, every one thought he was more than odd. Natural Gas was considered at that time a messy by-product of oil production that had to be disposed of. Even during the 1960s natural gas was still being flared at the wellhead in Oklahoma. During the 1940s, it was said that one could drive from Kilgore, Texas to Tyler, Texas at night without turning on the head light on your car due to all the gas flares. In this economic environment, measurement was not an issue if you could sell the gas at all it was considered a business coup. Even then, a good price was 2 cents an MCF. But when Henry Ford was building the Model T, gasoline was a refinery waste product that the heating oil manufacturers were glad to get rid of. Not so now. So, as with other cheap forms of energy, both the use and the infrastructure for natural gas grew. Natural Gas prices were tied to oil prices very tightly until the 1990s. If oil went up, so did Natural Gas. When it went down, down came the gas prices. Even though many electric power plants had been built with the capability to burn multiple sources of energy, like coal, oil and Natural Gas, the increasing pressure to clean up the environment, caused Natural Gas to become the preferred energy source. This factor plus the maturing pipeline infrastructure have now led to Natural Gas becoming its own independent commodity.
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Document ID:
399D1A0E
Energy Measurement Using On-Line Chromatographs
Author(s): Paul E. Kizer
Abstract/Introduction:
Most natural gas custody transfer contracts today use MMBtu2 rather than Mcf as the accounting units of gas transfer. This is, of course, a result of the Natural Gas Policy Act of 1978 (NGPA). An MMBtu, some times called a dekaTherm, is calculated by: Btu/cf * MMcf MMBtu A Btu is the acronym for British thermal unit. One Btu is the quantity of heat required to raise the temperature of one pound of water from 58.5oF to 59.5oF (about 1055.056 joules (SI))3. The Btu, then, is the measure of the actual amount of heat energy produced when a cubic foot (cf) of this natural gas oxidized, that is, burned.
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Document ID:
DDDD64A0
Field And Laboratory Testing Of Sediment And Water In Crude Oil
Author(s): Jane Williams
Abstract/Introduction:
The quantity of sediment and water in crude oil must be accurately established as part of the custody transfer process. Purchasers only pay for the crude oil received, and want to minimize the quantity of sediment and water they must dispose of. Consequently, monitoring of the sediment and water content is performed at the production site to prevent excessive sediment and water entering the pipeline system. The quantity of sediment and water a pipeline is willing to accept into their system depends on geographic location, market competitiveness and their ability to handle the sediment and water in the system. Each pipeline publishes the quantity of sediment and water it will accept.
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Document ID:
6204679F
Fundamentals Of Gas Chromatography
Author(s): John Renfrow
Abstract/Introduction:
The objective of the analyzation of natural gas by gas chromatography is to obtain a sample from the system in question and analyze the product without changing the composition or environment. There are 3 basic systems in obtaining a natural gas analysis by gas chromatography: 1. Sampling Systems 2. Gas Chromatography 3. Calculation of data. In this paper we will discuss each system.
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Document ID:
AABA5316
Measurement Of Liquified Petroleum Gas
Author(s): Ken A. Steward
Abstract/Introduction:
LPGs are classified as any hydrocarbon liquid having a vapor pressure greater than atmospheric. Under minimal pressures, LPGs can be held in the liquid state, which simplifies storage, transporting and measuring. When pressure is released, LPGs readily vaporize making them an ideal energy source for fuel when the vapor is ignited. The safest and most accurate method of transferring LPG from a bulk storage facility to a pipeline is through a reliable metering system. The basic concept in designing an LPG Metering System is to provide dependable components, which can safely be operated by trained personnel. In the case of a pipeline installation, the system must be designed to provide unattended operation with a minimum amount of maintenance. A transport loading system must provide a means to limit the filling of the transport and provide a hard copy of the total volume and the amount of odorant injected for each loading transaction.
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Document ID:
334FC5F7
On-Line Water Measurement Of Liquid Petroleum
Author(s): Steve Stewart
Abstract/Introduction:
The traditional method for determining water content in custody transfer measurement on hydrocarbon fluids has been product sampling, and product analysis. This sampling process has proven to be a laborious, and time consuming process, sometimes adding days or weeks to the custody transfer transaction. The purpose of an On-line Detector is to provide accurate, real time determination of water in a flowing hydrocarbon stream. Devices which can meet the strict accuracy and performance demands of todays oil industry serve a vital role in streamlining custody transfer and process control applications. Because of todays competitive energy market there is tremendous emphasis on accuracy, cost saving, and productivity at all levels of the industry the need for on-line automation of detecting water in hydrocarbon is paramount. Real time knowledge of water concentration in process streams or flowing pipelines is essential for improving system efficiency, safety, and streamlining system operations.
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Document ID:
E2A21C0D
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:
C9F06B69
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:
89858AE1
Techniques Of Composite Gas Sampling
Author(s): Stephen Palmitier
Abstract/Introduction:
The requirement for consistent, repeatable, representative gas samples is driven by both economics and by operations. The monetary value of the gas is principally determined by its energy content as expressed in British Thermal Units (BTU). The BTU value of the flow of natural gas needs to be established at various transfer points so that both parties to the transactions are treated equitably. The BTU value of the gas needs to be determined where it enters a plant so that operations may be balanced. Accurate samples are also important in maintaining the integrity of the pipeline. There are three basic methods for sampling gas. One method is to periodically take a spot sample. This is a relatively inexpensive method to sample but it leads to other problems that can be very expensive in other ways. A lot can change in the gas flow between the spot samples leading to inaccurate BTU values or undervaluing change that can impair pipeline integrity. Another method is the use of an online analyzer. This process is very expensive in the cost and maintenance of the equipment. Over time, the preferred method used to collect samples for analysis in determining BTU value has become the composite sample. By properly establishing the series of samples that make up the composite, it is possible to get a very good picture of the gas flow over time
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Document ID:
E00CDB5E
Techniques Of Gas Spot Sampling
Author(s): Donald P. Mayeaux
Abstract/Introduction:
Obtaining a spot sample of gas from a natural gas pipeline, at first glance, appears to be a simple and straight forward task. To the contrary, it is a complex task worthy of careful study considering the hundreds of millions of dollars that are at stake. The process of extracting a representative natural gas sample from a pipeline and transferring it into a cylinder is a major source of analytical error. There are several factors in the spot sampling process which have significant influence on the final analytical results.
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Document ID:
D812F17A
Determination Of Hydrocarbon Dew Point Using A Gas Chromatograph
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/N2 control and removal of Condensates), Coal Bed Methane producers (98% Methane), low cost producers (De-Hydration only) or global exporters of LNG. Economic factors have also played a role in the changing quality of the gas. As the Natural Gas prices have increased, producers who have previously stripped the heavier components out of the gas to produce condensates have realized a greater return by leaving the higher energy value heavy Components in the export Natural Gas.
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Document ID:
9E338422
Utilizing Equation Of State Eos() Software In Sample Conditioning Of Natural Gas Applications
Author(s): Donald P. Mayeaux
Abstract/Introduction:
Proper sample conditioning is essential to providing a representative sample of natural gas to the analyzer. Sample conditioning consists of extracting a sample from a process stream, transporting it to an analyzer, and conditioning it so that it is compatible with the analyzer. Conditioning generally consists of controlling the gas temperature, pressure, and flow rate. It also includes the removal of contaminates which may alter the sample composition and/or damage the analyzer. It is imperative that the gas sample composition is not altered or distorted during the conditioning process. Equations of State (EOS) software programs are useful tools for modeling the behavior of natural gas as it flows through a sample system. With the use of an EOS program one can determine if conditions in a particular sample conditioning system are conducive to the proper sampling of a specific natural gas composition. EOS software can be useful to the engineer or technician during the design, operation, and maintenance of a natural gas sampling system. This paper will discuss the types of information an EOS program can provide and how this can be utilized to solve common sample conditioning problems.
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Document ID:
3C870371
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:
515E3221
Reducing Measurement Uncertainty In Process Gas Quality Measurements
Author(s): Darin L. George
Abstract/Introduction:
The general term gas quality is used to refer to many different measures of the content of a natural gas stream. Common measures of gas quality include heating value, water vapor content, hydrogen sulfide or total sulfur content, levels of inert gases such as CO2, and hydrocarbon and water vapor dew points. These values determine how the gas stream must be handled, whether it can be used efficiently by customers, and whether the potential exists for damage to end-user equipment or pipelines that carry the gas stream. The presence of water and hydrogen sulfide in a gas stream, for instance, can create sulfuric acid and pit the walls of a pipeline. Shifts in heating value and specific gravity of the gas can lead to poor furnace performance, or require adjustments of gas-fired industrial equipment. High levels of non-hydrocarbon gases will reduce the heating value and make transportation of the gas less economically efficient. To determine whether natural gas meets gas quality standards in their transportation tariffs, producers and transmission companies must accurately measure all contents of the stream that affect gas quality. Accurate gas quality data will also be crucial to the effective introduction of liquefied natural gas (LNG) and marginal gas supplies into the natural gas transmission network in the near future. Accurate gas quality measurements depend not only on the instruments used to make measurements, but on the methods and equipment used to carry samples to the instruments
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Document ID:
4D48178B
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:
7480BC58
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:
C148F3E9
Fundamentals Of Pressure Regulators
Author(s): Gregg Schneider
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:
7D7C881E
Overpressure Protection Methods
Author(s): Gregg Schneider
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. Methods of Overpressure Protection The most commonly used methods of overpressure protection in the gas industry, not necessarily in order of use or importance include 1. Relief 2. Monitoring 3. Series Regulation 4. Shut-Off
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Document ID:
FB5E56BB
Prevention Of Freezing In Measurement And Regulating Stations
Author(s): David J. Fish
Abstract/Introduction:
The failure to supply natural gas upon demand can cause irreparable damage to a companys corporate image in the 21st Century. Consistent and continuous pipeline operations are key and critical factors in todays natural gas pipeline industry. The competitive nature of the business, together with the strict rules and regulations of natural gas supply, mandate that companies stay on top of all operational parameters that could cause interruption or complete shut-down of the natural gas supply to customers. Identifying what may ultimately cause problems is a first step to controlling and eliminating those problems for the supplier. The natural phenomenon of freezing is a common occurrence in the operation of a natural gas pipeline system. Whether the gas is produced gas from a crude oil well, or natural gas from a gas well, the possibility for hydrates and the resultant problems, is real. Freezing is a potential and serious problem starting at the production wellhead through the last point in the customer delivery system. The occurrence of freezing is continuously reduced each step of the way, but care must be taken at each and every step to assure smooth operational conditions and satisfied consumers at the end of the line. Freezing not only affects the pipeline itself but is also a significant contributor to measurement errors and to instrumentation upsets or failures. All of these potential issues will ultimately affect the overall pipeline operation and may have a major impact on the profitability of your company. The relatively small cost of prevention will produce large dividends from a successful and uninterrupted natural gas supply. Each situation differs from location to location. For this reason, there are several methods to combat freezing in the total spectrum of the natural gas industry.
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Document ID:
CDCC9C8B
Selection, Sizing, And Operation Of Control Valves For Gases And Liquids
Author(s): Corey Jansen
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:
8289F907
Turbulence And Its Effect In Measurement And Regulator Stations
Author(s): Tracy D. Peebles
Abstract/Introduction:
The effect of turbulence on measurement and regulator stations can cause erroneous measurement as well as pipe fatigue, noise levels that are not healthy for the human ear, and a host of other undesirable elements.
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Document ID:
FAE7AF45
Allocation Measurement
Author(s): Jeffrey L. Savidge
Abstract/Introduction:
Allocation is the process of assigning the proper portions of aggregated product flows back to individual source streams, owners, leases or measurement point. The assignment process is a standard method that is agreed upon and used by contracting parties. It is designed and intended to be fair, cost efficient and practical. By providing an efficient product sales transaction mechanism, allocation measurement helps to reduce capital and operating costs without jeopardizing the principal goal of fair treatment among parties. Reducing fluid measurement costs facilitates the development of marginal fields. Allocation measurement can fall under federal or regulatory guidelines. Individual agreements must meet or exceed those guidelines. API MPMS Chapter 20.1 is the industrys allocation measurement standard. Without it volumes of technical measurement documents would be required to accompany commercial contracts. The first edition of API 20.1 was prepared in 1993 and recently reaffirmed in 2006. Its scope is to provide a set of design and operating guidelines for implementing liquid and gas allocation measurement systems. As such, it provides recommendations for metering, static measurement, sampling, proving, calibrating, and calculation procedures. Due to the breadth of the measurement topics covered under allocation measurement, API Chapter 20.1 focuses on identifying procedures, providing practical and technical guidance in implementing allocation metering systems, and acts, in part, as a master guide to other important measurement guidelines.
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Document ID:
638BFC27
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:
B7997D68
Auditing Electronic Gas Measurement Per API Chapter 21.1
Author(s): Belenda L. Tonge
Abstract/Introduction:
What is an audit? According to Websters dictionary, an audit is an examination or verification of financial records or accounts. In the hydrocarbon industry, the financial records begin with the measurement data. Why audit? Specific reasons not withstanding, an audit is performed to ascertain the accuracy of the data upon which the exchange of money is based. What is needed to perform an audit? The wide spread use of flow computers changed the scope of the supporting information needed for determining the accuracy of the resulting volumes. Documentation for chart recorders is comprised of a paper chart, the integration statement, a gas analysis certificate and a meter inspection report, along with documentation of any change to the meters configuration. The petroleum industry recognized that a variety of electronic measurement recording devices would be used. Therefore, a set of standards was needed to establish minimum requirements for what these devices were to accomplish and what documentation would be needed in an audit trail. In September 1993, the American Petroleum Institute published Chapter 21, Flow Measurement Using Electronic Metering Systems, for inclusion into the Manual of Petroleum Measurement Standards. Section 1 covers Electronic Gas Measurement. Sub-Section1.6, Audit and Reporting Requirements, details what information is needed from an electronic gas measurement system for audit purposes
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Document ID:
ED5ADE6E
Overall Measurement Accuracy
Author(s): Paul J. La Nasa
Abstract/Introduction:
This paper presents methods for determining the uncertainty of both differential and positive metering stations. It takes into account the type of meter, number of meters in parallel, type of secondary instruments, and the determination of physical properties. The paper then relates this information to potential influence on system balance
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Document ID:
C55990CF
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:
3671C72C
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:
6C65AF83
Combining Intrinsic Safety With Surge Protection In The Hydrocarbon Industry
Author(s): Donald R. Long
Abstract/Introduction:
The Hydrocarbon Measurement Industry faces a rather unique combination of problems. First, many of the areas in and around pumping, custody transfer and storage areas are classified, or hazardous, that must, according to the National Electric Code, be assessed for explosion-proofing. This may be in the form of intrinsic safety barriers or isolators, explosion-proof enclosures and conduits, purged enclosures or non-incendive components. The second challenge facing the industry is the physical exposure of most of the electronic control and measuring systems, communications, and power subsystems, each with their own sensitive, high-performance microprocessors, etc., to potentially devastating lightning and electrical surges. The goal of this discussion is to explain just how to achieve both safety and surge protection in hazardous areas using nearly identical engineering techniques.
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Document ID:
EA5855F7
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:
91F549D2
Dot Qualification - Measurement & Control Technicians
Author(s): Jay Shiflet
Abstract/Introduction:
As a result of Congressional legislation, the Department of Transportation (DOT) Office of Pipeline Safety proposed the Pipeline Safety: Qualification of Pipeline Personnel - 49 CFR Parts 192 and 195 rule. The intent of this qualification rule (also referred to as the OQ rule or OpQual rule) is to ensure a qualified workforce and to reduce the probability and consequence of incidents caused by human error. The rule created new subparts in the gas and hazardous liquid pipeline safety regulations. These subparts established qualification requirements for individuals performing Covered Tasks, and amended certain training requirements in the hazardous liquid regulations. The pipeline industry worked closely with DOT to have the rule structured as a performance based rule. The rule places the compliance responsibility on the Operator. Within limitations, this permits the Operator a large measure of flexibility in the development and administration of the rules requirements. The rule defines the requirements for an activity to be deemed by the Operator to be a Covered Task. If the work activity is (1) is performed on a pipeline facility, and (2) is a operation and/or maintenance task, and (3) is performed as part of a requirement of DOT Part 192 or 195, and (4) affects the operation or integrity of the pipeline, the activity is a Covered Task.
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Document ID:
D1AFDEEF
Interface Detection In Liquid Pipelines
Author(s): Steve Stewart
Abstract/Introduction:
Since the earliest days of pipeline operations, refined products pipelines have been tasked with the challenge of developing interface detection methods to help identify, isolate, and store multiple fuel products as they flow through pipeline and fuel distribution networks. Although interface detection has been a standard procedure for many years in the pipeline industry, recent developments of specialty fuels such as reformulated gasolines, low sulfur fuels, and unique-blend fuels have created a renewed emphasis on interface detection. In order to meet this challenge, a need for improved interface-detecting technology, and improved interface-detecting procedures have been developed to help pipeline operators track and isolate products as they flow through the pipeline system.
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Document ID:
188C9294
Multiphase Flow Measurement
Author(s): Robert A. Webb
Abstract/Introduction:
Recognition of various real cases of multiphase flow are illustrated. Multiphase flow dynamics within pipes is related to various flow regimes encountered. Primary measurement using Venturi meters is highlighted and various associated or combined sensing technologies are examined. Techniques for both liquid and gas dominant flows are examined. Attention is given to researchers in the area of wet gas flow measurement using differential pressure meters. Techniques discussed include gamma ray densitometry, dual energy gamma spectroscopy, cross correlation, wet gas differential pressure meter over-read, dual differential pressure, tracer dilution, and partial separation
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Document ID:
B64AF75B
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:
DB254898
Orifice Meter Tube Dimensional Tolerances
Author(s): Rod Dent
Abstract/Introduction:
The orifice meter tube is the most widely used method of fluid measurement currently in use in the petroleum industry . Orifice fittings and orifice flanges developed to insert, retract, and hold the orifice plate in the meter tube in a dimensionally defined manner, are commonly used in meter tube assemblies. Each component of this meter tube assembly (normally welded and/or flanged together) must meet dimensional specifications of industry recommendations and standards (latest revisions) such as American Gas Association (AGA) Report No. 3- Part 2, the American Petroleum Institute (API) Chapter 14 section 3, ANSI, and ASME to name a few. This paper will discuss the manufacturing and fabrication dimensional tolerances involved in the design and construction of meter tubes.
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Document ID:
A9A16001
Program For Training A Measurement Technician
Author(s): Allen N. Chandler
Abstract/Introduction:
The need for quality measurement has increased dramatically in the past several years. Deregulation of market pricing structures, open access markets, increased exploration and drilling costs, fierce competition, and new regulatory requirements have all influenced todays approach to quality measurement methodologies. In fact, the terminology has evolved from gas volume measurement to total energy measurement. Today not only is the volume of gas a consideration, but also the quantity of energy the gas produces. Our industry has transitioned from the MMCF to the MMBTU for gas measurement. As technology has advanced, there has been a greater sense of urgency for employee training. The open-access market, which moves greater quantities of natural gas volumes with considerably lower profit margins, became a reality in the mid- to late-eighties. Measuring stations at transportation connects required a degree of accuracy that necessitated measurement personnel skilled in new technology. Such equipment as chromatograph analyzers, automatic samplers, flow computers, pressure and temperature transducers, and remote terminal units has come to the forefront of technology. New communication structures such as satellite systems, radio frequency data transfer, high-speed telephone modems, and cellular communications offer challenges to the field technician.
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Document ID:
DD895540
Vortex Shedding Meters
Author(s): Paul Warburton
Abstract/Introduction:
Vortex meters have proven to be repeatable, accurate and reliable flow meters for liquid, steam, and gas measurement applications. They provide turn down ratios as high as 30:1, low-pressure drops and no moving parts resulting in calculated mean time between failures (MTBF) exceeding 250 years. Recent advances in technology have dramatically improved meter performance, including those applications with inherent noise, making the vortex meter a viable choice for industry, and one of the fastest growing meter technologies in the world.
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Document ID:
A8AE32B7
The Effects Of Additives On Metering In Liquid Pipelines
Author(s): Jack Kiefert
Abstract/Introduction:
With the release of Ultra-Low Sulfur distillates around the world several issues have come to the surface in handling the new fuels. This paper will give a brief history of the Ultra-Low sulfur fuels, the downside of Sulfur reduction, and the solutions to best handle the fuels.
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Document ID:
C5CE2563
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:
CCEC6D64
Cone Meters For Liquid And Gas Measurement
Author(s): Philip A Lawrence
Abstract/Introduction:
This paper will describe how cone meters may differ from other differential pressure type meters as well as how they are used for the measurement of liquid and gas. The cone meter has become synonymous with specialist metering applications over the years due to the special traits that inherent by this type of meter design. The original concept venturi will be mentioned in the paper also for first principle overview purposes. Wet gas applications, liquids that have trash, ashphaltenes and wax in pipes , meter runs with short lengths offshore , steam measurement , custody transfer with end user- party agreement all which have been quite successful in implementation. Trade marks, current patented devices, or trade names will not be mentioned in this paper as per ISHM guidelines.
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Document ID:
279CD9F3
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:
BDF9D7C7