Measurement Library

International School of Hydrocarbon Measurement Publications (2004)

Download collection of documents about ISHM 2004 including table of contents, event organizers, award winners, committee members, etc.


International School of Hydrocarbon Measurement

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: 3D9E2F61

Coping With Changing Flow Requirements At Existing Meter Stations
Author(s): James m. Doyle
Abstract/Introduction:
Deregulation, competition, and increased share earnings. Do these terms sound familiar? Seems as though in todays market of the Oil and Gas Industry those terms are the basis companies must contend with. Companies must be firm and meet aggressive market strategies, or suffer the consequences. All industries have cash registers, and ours is no exception. Our measuring stations that measure our products are our cash register. These stations were designed ten, twenty, thirty even fifty years ago and are now are performing tasks they were not designed for. Therefore, changes must be made.
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Document ID: 8224BADD

Energy Measurement Using Flow Computers And Chromatography
Author(s): Burton G. 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.
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Document ID: 617BB346

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: 933336ED

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. An MMBtu 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 contained in a cubic foot (cf) of this natural gas. On line gas chromatography is today being chosen more often in the natural gas industry for monitoring of gas quality for the following reasons: The calculations of the gas volumes in modern electronic flow meters require not only Btu5,10,13 information, but relative Density (specific gravity, SG), Mol. % CO2 and Mol. % N2 and other components as well. The current AGA-8 compressibility calculation equations also require a complete analysis for the detailed method of calculation of FPV 15 The analysis information can be used to calculate the theoretical speed of sound using AGA 1016 The environmental installation requirements for Chromatographs are less stringent than calorimetric methods.
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Document ID: F5000914

Determination Of Leakage And Unaccounted-For-Gas Transmission
Author(s): David Beasley
Abstract/Introduction:
With the large volumes that todays Transmission companies are moving, the Loss and Unaccounted For Gas is an ongoing concern. Unaccounted for Gas is a term used to indicate the difference between the volume measured entering a pipeline and the volume measured out of the same pipeline. The difference is termed Loss and Unaccounted For Gas and can be expressed as a + or -. Since one normally thinks of pipeline loss, the - indicates a gain in the pipeline balance. Another shorter phrase used to identify the difference has been termed LUFG. The assumption is that all the gas is measured into and out of a physical pipeline that can be clearly defined. The smaller the pipeline segment and number of meters the more manageable the balance process becomes.
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Document ID: 89A77AC7

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: F4B8DD30

Effect And Control Of Pulsation In Pipeline Measurement
Author(s): Michael Royce Miller
Abstract/Introduction:
Pulsations created by compressors, flow control valves, regulators, and some piping configurations are known to cause significant errors in gas flow measurement. In recent years the Pipeline and Compressor Research Council (PCRC) now known as (GMRC) Gas Machinery Research Council a subsidiary of the Southern Gas Association, commissioned and funded various pulsation research projects at Southwest Research Institute (SWRI) in San Antonio, Texas. This research culminated in the publication of several technical papers, including the April 1987 PCRC report 10.87-3 titled Pulsation and Transient-Induced Errors at Orifice Meter Installations and the most recent technical report An Assessment of Technology for Correcting Pulsation Induced Orifice Flow Measurement dated November, 1991.
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Document ID: A77894CC

Fundamentals Of Gas Chromatography
Author(s): Matt Church
Abstract/Introduction:
Measurement of the quality of natural gas requires a variety of instrumentation, only one of which is the gas chromatograph. Contractual requirements frequently define the energy content, relative density, and moisture content of the gas being sold. The sale of natural gas is performed on the basis of the heating value per unit volume of the gas. For these reasons, the industry uses instruments to monitor the quality of the gas at the point of sale or at strategic locations along a pipeline. The following instruments are commonly found in the field and in the laboratory: Gas Chromatographs Moisture Analyzers Gravitometers Hydrogen Sulfide Monitors Others . . . . . Many of the instruments listed above are portable and many are installed as online instruments at custody transfer points. In many cases, sample cylinders are used to take a sample of the gas to a lab chromatograph for analysis. If the method used to capture a gaseous sample in the cylinder is not optimal, an inaccurate sample could be obtained. For this reason, the need for proper sampling systems and portable or online instrumentation has increased. With modern instrumentation, the analysis of the gas is taking place in the field without transferring the sample to a laboratory. In this article we will restrict our discussions to gas chromatography (Refs. 2,6,8) used to measure the composition and heating value of the natural gas.
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Document ID: ABF7EA18

Effects Of Abnormal Conditions On Accuracy Of Orifice Measurement
Author(s): Thomas B. Morrow
Abstract/Introduction:
In 1971 E. J. Burgin of Florida Gas Transmission Company presented a paper at ISHM entitled Factors Affecting Accuracy of Orifice Measurement (Primary Element). Burgin noted that A.G.A. Report No. 3 (of that time) claimed that an orifice meter with flange taps and with a diameter ratio, , between 0.15 and 0.7, fabricated and operated in accordance with the specifications in the standard, would have a discharge coefficient value within 0.5% of the value calculated from the orifice equation. The purpose of Burgins paper was to examine some of the specifications in the orifice meter standard and to review the effect upon measurement accuracy when the specifications are ignored.
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Document ID: F4E16765

Fundamentals Of Gas Measurement I
Author(s): Douglas E. Dodds
Abstract/Introduction:
To truly understand gas measurement, a person must understand gas measurement fundamentals. This includes the units of measurement, the behavior of the gas molecule, the property of gases, the gas laws, and the methods and means of measuring gas. Since the quality of gas is often the responsibility of the gas measurement technician, it is important that they have an understanding of natural gas chemistry.
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Document ID: 8D138AA2

Light Hydrocarbon Liquid Sampling
Author(s): Garrett Lalli
Abstract/Introduction:
Identifying the individual hydrocarbons in a light liquid hydrocarbon stream is essential in the determination of the dollar value of the product being purchased or sold. It is also very crucial to the process of auditing plant performance and system balance. To satisfy these business needs, light liquid hydrocarbon sampling systems and proper sampling techniques are fundamentally required. A typical sampling system application is one that is used on a mass measurement station. The primary instruments of a station include a turbine meter, temperature probe, pressure transducer, and a densitometer to determine the volume and density of the product. By measuring these variables, we determine mass (volume x density mass). While the station is calculating mass per metered volume, a sampling system is taking small samples of the flowing stream and storing them in an accumulator. The liquid phase composite sample retrieved is injected into a chromatograph and each component, along with its molecular weight fraction, is identified. Knowing the molecular weight fraction of each component, as well as the total mass of each volumetric unit measured, makes it possible to determine how much of each hydrocarbon component is contained in each volumetric unit sold.
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Document ID: 531E659D

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.
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Document ID: A927F130

Measurement Of Liquefied Petroleum Gases Lpgs()
Author(s): Henry A. James
Abstract/Introduction:
Liquidified Petroleum Gas (LPG) is defined as butane, propane or other light ends separated from natural gas or crude oil by fractionation or other processes. At atmospheric pressure, LPGs revert to the gaseous state. This paper is intended to provide an overview of metering systems used for the volumetric measurement of LPGs. Operational experiences with measurement systems will be addressed that often degrade the performance of these systems. It includes information for turbine and positive displacement meters used in volumetric measurement systems. The basic calculations and industry standards covering volumetric measurement will also be covered.
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Document ID: AC8B07BD

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 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: 9ECC1129

On-Line Water Measurement Of Liquid Petroleum
Author(s): Kim Mohajer
Abstract/Introduction:
Traditionally a sample of liquid petroleum has been taken either manually or automatically and analyzed for water in accordance to the industry standards. On-line water measurement of liquid petroleum will provide real time knowledge of the water content of the liquid petroleum, and will afford the user the luxury of total automated measurement. The purpose of an On-line Water Detector (OWD) is to provide accurate, real time measurement of the water in a flowing hydrocarbon stream or tank. Different OWD applications such as reservoir management, production, production allocation, production separation, production transportation, custody transfer, refinery feedstock, process, and etc. require a different level of accuracy. The OWDs that can meet the strict accuracy, reliability repeatability, serviceability, performance, ease of installation, cost of ownership, maintenance, and performance demand of todays oil industry can serve a vital role in the automation. In todays competitive energy market there is tremendous emphasis on 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 by the means of automation.
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Document ID: D7A1FBA1

Fundamentals Of Gas Turbine Meters
Author(s): Robert Bennett
Abstract/Introduction:
Gas measurement in the U.S. and around the world is dominated by diaphragm, rotary, turbine, and orifice meters. Each serves a different segment of the gas industry and each has its own set of advantages and disadvantages. These four main types of meters can be broken into two distinct categories: positive displacement, and inferential. Diaphragm and rotary meters fall into the positive displacement group because they have well-defined measurement compartments that alternately fill and empty as the meter rotates. By knowing the volume displaced in each meter revolution and by applying the proper gear ratio, the meter will read directly in cubic feet or cubic meters.
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Document ID: 6E6CF225

A Review Of API Chapter 14.1
Author(s): Eric Kelner, Darin L. George
Abstract/Introduction:
Over the past eight years, the Gas Technology Institute (GTI), the American Petroleum Institute (API) and the United States Minerals Management Service (MMS) have co-sponsored an extensive natural gas sampling methods research program at the Metering Research Facility (MRF), located at Southwest Research Institute (SwRI). The results of this research provided a basis for the revision of Chapter 14.1 (Collecting and Handling of Natural Gas Samples for Custody Transfer) of the API Manual of Petroleum Measurement Standards (MPMS). The revision is complete and was published in 2001. The API Chapter 14.1 Working Group, a research steering committee consisting of natural gas sampling experts from major oil and gas companies, provided input that helped focus the project on improving current field practices. The research identified several causes of natural gas sample distortion, as well as techniques for avoiding gas sample distortion. The research data illustrated how errors in calculated gas properties, such as heating value and density, can occur as a result of poor sampling techniques.
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Document ID: B298254D

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.
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Document ID: 62FA39DA

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: 49E5AE2D

Installation And Operation Errors In Gas Measurement
Author(s): Johnnie Jarred
Abstract/Introduction:
This paper is intended to meet three primary objectives. 1) Outline some of the most popular/common installation and operation errors in various primary elements. 2) Outline some installation and operation errors in the various secondary and tertiary devices. 3) Provide some guidance on overall application of natural gas measurement standards and provide sources for gaining additional knowledge and expertise in this area. The real question that we are continually asked is What is the error? If we know the answer to this we can determine the economic value of replacing the legacy facilities. This economic impact is generally reflected in lost and unaccounted for gas.
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Document ID: 4CA9246E

Low Pressure Gas Measurement Using Ultrasonic Technology
Author(s): Burt G. Reed
Abstract/Introduction:
The ultrasonic metering technology has reached a high degree of maturity and acceptance throughout the measurement industry. In order for this technology to reach the acceptance levels comparable to conventional metering technologies such as orifice meters and turbine meters the application range of ultrasonic meters needs to be expanded. In addition to the high volume flow metering sites in gas transmission pipelines there is a need to measure natural gas at low pressures downstream of transmission lines using new metering technologies.
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Document ID: 304AF0CB

Sample Conditioning And Contaminant Removal For Water Vapor Content Determination In Natural Gas
Author(s): Brad Massey
Abstract/Introduction:
The Natural Gas Industry experiences numerous operational problems associated with high water vapor content in the natural gas stream. As a result several problems are experienced such as, equipment freezes, dilution of physical properties reducing heating value, volume measurement interference, and pipeline corrosion. Contracts and Tariffs usually limit the amount of water vapor content allowed at the custody transfer point. For these and other reasons, accurate Water Vapor Dewpoint measurements are critical measurements for all companies involved in natural gas production, gathering, transmission and delivery. The industry continues to experience problems in obtaining accurate water vapor dewpoint measurements, primarily due to interference problems associated with contaminants and poor sampling techniques. Various types of analytical equipment are being used to determine Water Vapor Dewpoint Measurements. All are susceptible to contaminate interference or poor sampling techniques being utilized. Proper design and utilization of the correct type of sample conditioning devices or improved sampling techniques will provide much more reliable results, regardless of the equipment being utilized. This paper is intended to address these problems and provide some practical solutions by utilizing improved sampling procedures, including properly placed and specific filtration methods.
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Document ID: 05277A29

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 or more than 350,000 units. Newer designs have shown greatly improved low-flow sensitivity, lower pressure drop, and immunity to noise factors which now enable their successful use in gas-phase fluid applications. With more than 20,000 units on gas around the world, measurement organizations around the world are involved in writing standards for this emerging gas flow technology.
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Document ID: 15CB2024

Techniques Of Composite Gas Sampling
Author(s): Josh H. Welker
Abstract/Introduction:
What is composite gas sampling? In ASTM Designation: D 5287-92: Composite gas sampling is the use of a mechanical system to compile representative samples in such a way that the final collection is representative of the composition of the gas stream. In ISO/DIS 10715: Composite sampling is accumulating a series of spot samples into one composite sample. Today, two major groups within the natural gas industry take samples. These are the gas measurement groups and the corrosion protection groups. The gas measurement groups need samples to get the British Thermal Unit (BTU) value and the specific gravity of the gas. The corrosion groups need samples to determine what is in the flowing fluid so that they can prevent the pipeline and associated instruments from corroding. Before participating in composite gas sampling, a user needs to know what a representative sample is. An overview of the components used and an understanding of the set up of a sampling system are also needed in order for a user to properly perform composite gas sampling techniques.
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Document ID: E82ADB5D

Measurement Station Inspection Program And Guide
Author(s): Robert J. Rau
Abstract/Introduction:
Today, lets discuss an important phase of everyday planning for the Measurement personnel. A test and inspection guide is a corporations plan to meet government regulations. DOT requires pipelines to have a written operating and maintenance plan. This plan must meet the minimum federal standards and cover various phases of operations. A company may include items above the minimum federal standards but they must operate according to the plan they prepare. In plain words, what you write you must be ready to live and operate by whether they just meet the DOT minimums or exceed the DOT requirements and this becomes the company bible. The last item to remember is that as field personnel you must perform the required inspections, complete properly the administrative records to document and prove that required tests were made. This is an important item as it involves personal honor and your signature is your statement the work was done. Government penalties applied to companies can be very high if the required work is not done, or has not been properly documented. If the work is not done, admit an error was made. It helps with DOT inspections if an explanation is in the file as to why the specific test was not performed, such as weather prevented transportation offshore or station shut in because well is dead.
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Document ID: F561A156

Techniques Of Gas Spot Sampling
Author(s): Tom Welker
Abstract/Introduction:
Gas sampling is defined by the Gas Processors Association Publication 2166. The object of any sampling procedure is to obtain a representative sample of hydrocarbons from the system under investigation. Any subsequent analysis of the sample regardless of the test is inaccurate unless a representative sample is obtained. Due to the wide variation in flowing streams and the components in these streams, the proper sampling techniques must be employed in order for the sample to be taken, transported, stored, and finally analyzed by some type of test device. The first factor that must be covered is the person chosen to physically take the spot sample or install and maintain the sampling device. This person is the beginning of a successful sampling program. The final outcome of the sample operation will be determined by the efforts of this first link in an unbreakable chain of operations that must be performed without variances that can and will affect the outcome of the results obtained.
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Document ID: 7EA677F2

Ultrasonic Gas Flowmeters For Custody Transfer
Abstract/Introduction:
This paper presents an outline of the theory and methods applied in ultrasonic gas flow metering for custody transfer. The development of a multipath instrument for custody transfer will be discussed, and recent developments will be indicated. Practical applications are illustrated using the Instromet 3 path and 5-path Q.Sonic custody transfer flowmeter.
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Document ID: B1A3C682

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 affect on the system stability.
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Document ID: 55D919F0

Orifice Fittings And Meter Tubes
Author(s): Ken Embry
Abstract/Introduction:
Throughout the oil and gas industry, the need for reliable measurement has been satisfied over many decades through the use of orifice meters. The orifice meter is the most common meter in use today and can satisfy most application requirements. This paper will address the basic theory of measurement and overview primary orifice fittings and meter tubes.
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Document ID: 841EAC96

Fundamentals Of Pressure Regulation
Author(s): Bill Hobson
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: 2C012922

Orifice Meters Operation And Maintenance
Author(s): Jeffrey L. Meredith
Abstract/Introduction:
Accurate measurement is of utmost importance to all companies involved in the purchase or sale of natural gas. Orifice meters act as a cash register for the industry. Proper operation and maintenance of the orifice meter is essential to ensure that both producers and customers receive an accurate account on every delivery. The orifice meter was developed in the early 1900s. They have become the industry standard for measurement of large volumes of natural gas.
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Document ID: 3D7CAE81

Fundamentals Of Pneumatic Controllers
Author(s): Jeff Bell
Abstract/Introduction:
Controllers are a familiar sight in most industrial operations. The performance of these important components determines the quality of performance provided by a complete control system. Optimum performance results from understanding fundamental relationships of controller actions and making the proper adjustments to suit the process. Most standard controllers have three common modes of operation: proportional mode, reset or integral mode, and rate or derivative mode. This paper will discuss the effects of each mode and the corresponding construction of a controller. Controllers measure a signal from a measuring element. This input signal represents the value of a process variable, whether it is at steady state or changing. Pneumatic controllers utilize compressed air as the supply of the signal.
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Document ID: AB4E3B6C

Problems Unique In Offshore Gas Measurement
Author(s): Jackie R. Tims
Abstract/Introduction:
Some major problems and unique solutions will be addressed with gas measurement on offshore platforms in the Gulf of Mexico. This presentation will show the major roll safety, transportation, and weather play in the technicians ability to verify the accuracy of the gas measurement facility. Proper operation, design, and installation will ensure accurate measurement.
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Document ID: 1064B9B5

High Pressure Regulators
Author(s): Robert Bennett
Abstract/Introduction:
A regulator may be described as a mechanism for controlling or governing the movement of machines or the flow of liquids and gases, in order to meet a standard. The primary function of a gas or liquid regulator is to match the supply of the fluid moving through it to the demand for the fluid downstream. To accomplish this, the regulator continuously measures the downstream pressure and makes adjustments accordingly.
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Document ID: E90B1C5C

Thermometry In Gas Measurement
Author(s): Joshua J. Kinney
Abstract/Introduction:
There are many conditions in natural gas flow measurement that can cause undesirable errors that are difficult to pinpoint. Finding inconsistencies in large measurement systems is cumbersome, especially if the base measurements are in error. To determine reliable natural gas volumes, all variables must be measured correctly. When temperature is measured incorrectly, it can have a pronounced effect on overall flow measurement.
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Document ID: E9889AE7

Operation & Maintainance Of Regulators
Author(s): Mark Windsor
Abstract/Introduction:
There has been much written on the assembly and the principle operation of regulators. In fact each manufacturer provides a written statement on the operation of each of its regulators as well as the method of dissembling and assembling the regulators when overhauls are needed. I was involved for ten years in the testing and overhauling of stations in the field. Part of my job was to test and prove operation of regulators we were currently using as well as determine through destructive testing, what regulators we would use and would not use. I have directed the repair and overhaul of well over 10,000 stations across Texas used for the delivery of gas to town plants, districts, or large industrial plants or colleges. Many times the literature provided by the manufacturer can only be understood by personnel with a clear understanding of the operation or the language used when describing regulators. However, over the years many of the people dealing with regulators have adopted their own language. For this reason many times much of the most critical information needed to understand how to select a regulator is not reviewed. After it is installed, the field operator is either unaware of how to correct problems by altering the regulator with factory parts or cannot correctly identify the problem and report it in a manner which will lead to a resolution. Some operators feel they are not in a position to report it, therefore resolutions are never found. This usually leads to the keeping of higher pressures on the outlet side than are necessary. In short, LUG is increased, system maintenance is increased, leak investigations are increased, gas velocities are significantly decreased and profits are significantly decreased just to name a few problems. I would like to provide you with a method of determining which stations can be set to properly control gas flow and pressure in a manner which will be efficient and profitable. When setting stations to flow with other stations on the same line, other knowledge is needed in order to ensure that all will be flowing in order to meet the target pressure. Setting all the stations to flow at exactly the same pressure on a looped system only ensures that some will be flowing and some will not at a time when they are all needed.
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Document ID: 5C08AD5C

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: 7556E100

Wet Gas Measurement
Author(s): Joshua J. Kinney
Abstract/Introduction:
In the natural gas industry, proper flow measurement is one of the key elements in providing accurate allocation of revenue. Natural gas can have some liquid content. This liquid may be water, hydrocarbons, compressor oil or a mixture of all three. When a flow meter is subjected to wet gas, large errors in flow measurement can be present with undesirable results to the bottom line. The intention of this paper is to introduce the reader to the difficulties associated with wet gas. The content presented is not intended for wet gas measurement error correction. The first section gives a brief glossary of terms used when describing wet gas flow. The next section gives a simple discussion about the behavior of a wet gas mixture from the first appearance of liquid to large amounts of liquid present in the gas stream. Also, previous research conducted in a controlled environment pertaining to the effect of entrained liquids on orifice measurements is described. Finally, general discussions about wet gas metering is discussed.
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Document ID: 6212225A

Selection, Sizing, And Operation Of Control Valves For Gases And Liquids
Author(s): Jeff Bell
Abstract/Introduction:
Proper control valve sizing and selection in todays industrial world is essential to operating at a costeffective and highly efficient level. A properly selected and utilized control valve will not only last longer than a control valve that is improperly sized, but will also provide quantifiable savings in the form of reduced maintenance costs, reduced process variability, and increased process availability. An undersized valve will not pass the required flow, while a valve that is oversized will be more costly and can cause instability throughout the entire control loop. 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: 250FDC92

Application Of Densitometers To Liquid Measurement
Author(s): Marsha Yon
Abstract/Introduction:
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 and from 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: D9B65320

Application Of Turbine Meters In Liquid Measurement
Author(s): Don Sextro
Abstract/Introduction:
Turbine meters are found around the world measuring crude oil, intermediate and finished products, and light hydrocarbons such as ethane, propane, butanes, and natural gas liquids (NGL) mixtures. Their performance and durability have enabled turbine meters to be used for custody transfer, check and operational measurement in the petroleum industry. In custody transfer applications, there are a number of industry standards to guide a user in the design, construction, operation and maintenance of the turbine meter and its associated equipment. This paper presents the issues associated with applying turbine meters in liquid hydrocarbon measurement from the perspective of a user who needs to select and install a meter for custody transfer purposes. In a non-custody transfer application, a user may consider following the standards and practices applied to custody transfer meters to achieve accurate and reliable results.
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Document ID: E3DA4B63

Calculation Of Liquid Petroleum Quantities
Author(s): Peter W Kosewicz
Abstract/Introduction:
In the Petroleum industry as hydrocarbons are purchased, sold or transferred there are two key elements that must be determined. These elements are the quantity and quality of the hydrocarbon in question. This paper will address one of those elements, the determination of the quantity of the hydrocarbon in the transaction. The determination of the quantity of hydrocarbon can be further subdivided into: Static quantity determination and Dynamic quantity determination Static quantity is determined when the hydrocarbon is measured under non-flowing conditions, such as when contained in a tank, rail car, truck or vessel. Conversely Dynamic quantity determination occurs when the hydrocarbon is measured under flowing conditions.
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Document ID: 94094A4E

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: C528CD4B

Liquid Allocation Measurement
Author(s): Raymond Gray
Abstract/Introduction:
portion of the royalty meters volume is attributable to a particular lease, well, or measurement point. Some allocation points fall under federal guidelines, while others fall under other regulatory bodies. Individual contractual agreements must meet and will often exceed regulatory guidelines. Therefore, certain accuracy and procedural standards are set. These standards are intended to treat all producers uniformly, to be fair to the small producer as well as the larger ones. In September 1993, the American Petroleum Institute published MPMS chapter 20, Section 1, entitled Allocation Measurement. Chapter 20 is a document outlining a set of recommended standards, to be used as a general guideline in all allocation applications.
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Document ID: 4BFB3DB5

Audit Of Electronic Gas Measurement
Author(s): Bob Abraham
Abstract/Introduction:
Auditing electronic gas measurement data is basically the same as the auditing of orifice charts. Given the rapid changes in electronic gas measurement (EGM) technology, the auditor must gather a combination of electronic files and paper documents in order to audit EGM data. The main objective when auditing electronic gas measurement data is to verify all the base measurement data is correct and that the proper electronic data files are processed for the audited metering station. This will require either a hard copy report or the ability to accept the raw data files from the particular EGM device into a computer.
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Document ID: BE71292A

Calibration Of Storage Tanks
Author(s): m. J. Yeandle
Abstract/Introduction:
This paper will discuss several field measurement methods that are presently in use to calibrate upright, above ground, cylindrical, cone and floating roof steel storage tanks.
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Document ID: 1CCF0952

Crude Oil Gathering By Truck - Metering Versus Manual Gauging
Author(s): Bobby Moore
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: 580850FE

Auditing Gas Measurement And Accounting Systems
Author(s): Donna Marshall
Abstract/Introduction:
Costly mistakes can be made if there are not proper procedures or guidelines in place once the new Gas Measurement or Accounting Systems have been implemented. A thorough audit will need to be conducted prior to reporting any of the final MCF or MMBTU volumes.
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Document ID: 2C28B497

Design, Operation And Maintenance Of Lact Units
Author(s): James King
Abstract/Introduction:
This paper presents an overview of the design, operation and maintenance of Lease Automatic Custody Transfer (LACT) units. These units are used for the automatic unattended measurement of quantity and quality of crude oil and sometimes other wellhead liquids when transferred from a producer to a pipeline for the account of a purchaser or consignee. This transfer usually takes place at a production lease site, hence, the use of Lease in the name. This can be on land or offshore delivering into pipelines, barges, or tanker loading and offloading operations. Similar units used to measure the transfer of other liquids or liquids between pipelines are often called ACT units since they usually are not associated with a crude oil production lease. LACT units can range from small single meter, low pressure systems with portable proving connections to high-pressure systems with multiple meters and an on-site dedicated meter prover. Multiple smaller meters in parallel, instead of a single large meter, permit a larger range of permissible flow rates and reduces the prover size. Additionally, if one meter run fails, the LACT Unit can still operate at a somewhat lower capacity. LACT unit configurations vary considerably, but most units contain the basic equipment described here. More detail can be found in the American Petroleum Institute Manual of Petroleum Measurement Standards (API MPMS) Chapters 5, 6, 7, 8, 9, and 10. To ensure correct measurement of a petroleum liquid, the Lease Automatic Custody Transfer (LACT) equipment just be properly designed, operated and maintained.
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Document ID: FBC27A3F

Auditing Liquid Measurement
Author(s): Linda A. Larson
Abstract/Introduction:
An effective audit of liquid hydrocarbon measurement is dependent upon a solid understanding of the measurement process combined with the application of sound internal auditing principles. The quality of liquid measurement activities is contingent upon (1) the reliability of the measurement equipment and instrumentation used (2) the specific procedures and practices followed in performing the measurement activities (3) the adequacy of training and proper performance of the measurement technician and (4) the proper documentation of transactions based on a measured value. All four components must be taken into consideration when auditing liquid measurement. In addition, to ensure the efficiency of the audit process, auditors must identify those areas which present the greatest risk to the organization to achieving its goals, and concentrate audit effort on those areas.
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Document ID: 300AABA7

Pdisplacement Meters For Liquid Measurement
Author(s): R. Gary Barnes
Abstract/Introduction:
This paper will examine the strengths and weaknesses as well as design principles that are fundamental to capillary seal PD Meters. It will also highlight the system and the parameters that must be considered before accurate meter selection can be made. Comparisons will be presented utilizing the six (6) most common PD Meter principals: (1) Oscillating Piston, (2) Sliding Vane, (3) Oval Gear, (4) Tri-Rotor, (5) Bi-Rotor, (6) Nutating Disc.
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Document ID: 2012A3A0

Overall Measurement Accuracy
Author(s): Paul J. Lanasa
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: E64F54C2

Effects Of Flow Conditioning On Liquid Measurement
Author(s): Klaus J Zanker
Abstract/Introduction:
Pipe fittings such as: bends, Tees, reducers, headers, valves, filters, strainers, heat exchangers, etc, affect the velocity profile in the downstream pipe. These profile distortions are known to affect the performance of flow meters. The magnitude of the effect depends upon both the severity of the distortion and the sensitivity of the meter (Ref. 1). One solution to these problems is to use long straight lengths of pipe upstream of the meter. Friction effects on the wall of the pipe will eventually extend to the center of the pipe to produce a fully develop velocity profile, which no longer changes with any additional pipe length. Unfortunately this can take very long lengths (hundreds of diameters), which is often neither practical nor economic. Other possible solutions are to design meters that are less sensitive to velocity profile distortions, or design flow conditioners that produce good velocity profiles in very much shorter lengths of straight pipe.
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Document ID: 8D7D65BF

Overview Of API Copm() - Measurement Activities
Author(s): Jon Noxon
Abstract/Introduction:
The American Petroleum Institute was founded in 1919 as an outgrowth of the National Petroleum War Committee. That committee was comprised of U.S. oil industry leaders who worked together with the federal government to meet the tremendous demand for petroleum fuel during the First World War. The experience demonstrated that oil industry representatives could work together on common problems affecting the industry and still compete with one another in the marketplace. This in an important concept because industry competitors could now work together toward mutual objectives, using API as the forum, without violating U.S. antitrust laws.
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Document ID: AF3A11F6

Polymer-Grade Ethylene Measurement
Author(s): James E. Gallagher, Henry James
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 degF
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Document ID: 2EDB2BBB

Simplified Statistics
Author(s): Wesley G. Poynter
Abstract/Introduction:
The objective of this paper is to describe some basic statistics in simple language, and to give the user some guidance as to when it may not be necessary to stick to the rigorous rules of formal statistics. This intent is for the everyday use of measurement people who may use some statistical tools to help do their jobs better. The user should be aware, though, that these simplifications may not be defensible in litigation.
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Document ID: 4CF1F6C9

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: 93BE58D5

Calibration Using Portable Digital Pressure Indicators
Author(s): Leo J. Buckon
Abstract/Introduction:
The use of electronic pressure calibrators in the gas industry has added new concerns and issues in pressure measurement. Readings appeared that perhaps didnt match the old reliable standby calibration readings or methods, and terms like sensitivity, accuracy, resolution, stability and traceability have become common. Technicians began using correction factors to achieve standard conditions. These correction calculations presented challenges to technicians when performing their calibrations. They began to see the effects of temperature on their test instruments and how temperature affects the accuracy of the gas measurement. More recently, the wide spread use of digital field devices such as smart transmitters has continued to change the technicians world as new tools became necessary to configure and maintain field instrumentation. When using electronic pressure calibration equipment, technicians can make their job easier if they identify and purchase instruments that are traceable, precise, accurate, sensitive, and repeatable. The American Petroleum Institute Chapter 21 gives good advice and recommendations in this area. Communications capability and multi-functionality also help the technician to be more productive in the field.
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Document ID: 38BD0734

Fundamentals Of Liquid Measurement - Part 1
Author(s): Ralph S. Papesh
Abstract/Introduction:
Accurate liquid measurement is an important aspect of the petroleum industry. With regard to commerce, it is the basis of custody transfer between producers, pipelines, refineries, petrochemical plants, utility plants, products marketing and the transportation industry. As it pertains to process control, it is needed to maintain specific flow rates, pressures and levels to ensure precise quality and environmental control. In either custody transfer or process control, daily small percentage volumetric measurement errors can accumulate to large volumetric errors over a long period of time. These errors can have an adverse impact on the profitability of a company. In order to help minimize liquid petroleum measurement inaccuracies, a fundamental understanding of the physical laws that affect measurement are necessary. Therefore, while knowledge of measurement equipment principles and applications are necessary to design or maintain an accurate system, it is equally important to understand the hydrocarbon physical properties that affect volume, oil quality, the method of measurement, and consequently, the price of oil. These physical properties include: Temperature, Density (or relative density, or API gravity), Compressibility, Sediment and water (S&W), Vapor Pressure (RVP or TVP), and Viscosity.
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Document ID: F6F134A4

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, highperformance 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: 71AD800E

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: 1DB05E71

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: C88E5C3B

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. The means of measuring hydrocarbon liquids fall into one of two methods: Static measurement Dynamic measurement Static measurement is performed when the hydrocarbon liquid is at rest and contained within a container such as a tank, hence it is commonly referred to as Tank Gauging. On the other hand when hydrocarbon liquids are measured while in motion, this is referred too as dynamic measurement or Metering. Another why to think of the difference in measurement techniques is to think of static measurement as measuring the volume in a container at a point in time and dynamic measurement as measuring the volume in a container over time. This paper will examine the various types of meters, their accessories and the devices to verify the meters performance.
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Document ID: C01D2D5D

Dot Qualification - Measurement & Control Technicians
Author(s): Jay Shiflet
Abstract/Introduction:
As a result of Congressional legislation, the Department of Transportation (DOT) Office of Pipeline Safety proposed the Pipeline Safety: Qualification of Pipeline Personnel - 49 CFR Parts 192 and 195 rule. The intent of this qualification rule (also referred to as the OQ rule or OpQual rule) is to ensure a qualified workforce and to reduce the probability and consequence of incidents caused by human error. The rule created new subparts in the gas and hazardous liquid pipeline safety regulations. These subparts established qualification requirements for individuals performing Covered Tasks, and amended certain training requirements in the hazardous liquid regulations.
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Document ID: C2CF594A

Fundamentals Of Liquid Turbine Meters
Author(s): Joshua W. Rose
Abstract/Introduction:
Turbine meters have been used for the custody transfer of refined petroleum products and light crude oils for over 30 years. When correctly applied, they offer high accuracy and long service life over a wide range of products and operating conditions. Traditionally turbine meters were used for the measurement of low viscosity liquids and PD meters for higher viscosities. However, new developments in turbine meter technology are pushing these application limits while increasing reliability and accuracy. This paper will examine the fundamental principals of turbine meter measurement as well as new developments including: smart preamps for real-time diagnostics, helical flow turbine meters for higher viscosity applications, higher performance flow conditioners to increase accuracy, and viscosity compensation to extend the application limits.
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Document ID: C7C66A70

Instrument Calibration Using Pneumatic Dead Weight Tester
Author(s): Roger Thomas
Abstract/Introduction:
One of the most difficult problems facing the instrument engineer is the accurate calibration of pressure or differential pressure measuring instruments. The deadweight tester or gauge is the economic answer to many of these problems. This paper describes methods to select deadweight testers and gauges. Also included are procedures for using pneumatic and hydraulic deadweight testers.
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Document ID: 14A498AA

Gauging, Testing And Running Of Lease Tanks
Author(s): George L. Lewis
Abstract/Introduction:
Gauging is a measurement procedure whereby the QUANTITY and QUALITY of the crude oil are determined at the point of sale by a company gauger or other designated representative, such as a Crude Oil Truck Driver (COTD). Typically, we think of lease tanks as having volumes of less than 1,000 barrels. The gauger is primarily responsible for rejecting nonmerchantable crude oil and buying accurate volumes of merchantable crude oil that can be refined, traded, or sold. His company is fully dependent upon his competence and sound judgment, while his high public visibility requires him to be conscientious, accurate, professional, and courteous.
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Document ID: 0C509CBC

Interface Detection In Liquid Pipelines
Author(s): Bobbie W. Griffith, Jr.
Abstract/Introduction:
There are over 160,000 miles of liquid pipelines in the United States. The majority of these pipelines carry multiple fluids in the same line. The pipelines are generally grouped into two categories, crude oil pipelines and product pipelines. In both types of pipelines the different fluids are batched into the line and the line is operated in order to minimize mixing of the different fluids. However, there is always part of the batch that mixes with the batch before or after it. If the two fluids are compatible, such as regular unleaded and super unleaded gasoline, then this is referred to as a compatible interface. If the two fluids are incompatible, such as diesel and gasoline, then the interface forms a transmix. Pipeline operators will order the batches in such a way to reduce the degradation of the value of this transmix fluid. It is necessary to detect the interface or transmix when it reaches the distribution point. It is important that this can be done quickly and reliably for all batches transported in a pipeline. Generally the physical properties of the fluids are used to determine the arrival of the interface. The remainder of this paper will focus on the technologies available to detect these interfaces.
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Document ID: 12F74E60

Helical Turbine Meters For Liquid Measurement
Author(s): Joshua W. Rose
Abstract/Introduction:
Turbine meters have been used for the custody transfer of refined petroleum products and light crude oils for over 30 years. When correctly applied, they offer high accuracy and long service life over a wide range of products and operating conditions. Traditionally, turbine meters were used for the measurement of low viscosity liquids and positive displacement meters for higher viscosity fluids. However, new developments in turbine meter technology are pushing these application limits while increasing reliability and accuracy. This paper will examine the fundamental differences between conventional and helical turbine meter measurement. It will also discuss new developments in flow conditioning, helical meter proving and viscosity compensation to extend turbine meter application limits.
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Document ID: D1B188E1

Multiphase Flow Measurement
Author(s): Parviz Mehdizadeh
Abstract/Introduction:
Production measurements have had to deal with a major challenge. We have had to use single-phase measurements devices to assess the flow of multiphase streams. Much research has focused on devising ways to adopt these single-phase devices to measurements of multiphase streams. This paper describes the development of multiphase meters, how they work, their deployment, and applications. Periodic well testing and production measurements provide data that is used for field and well allocation in the upstream petroleum industry. In general, allocation is defined as the process of matching cumulative volumetric production measurements at various locations in the production train. Reporting and back allocation of oil, gas, and associated products builds the primary basis for the performance measurement of operations for a producing asset. The allocation procedure provides the basic requirements for reporting of data and the pro-ration of sales volumes, re-injected volumes, disposed volumes, and volumes allocated to individual properties/wells/reservoir/zones, as shown schematically in Fig. 1. The need for production allocation rises from the unavailability of accurate measurement of oil, gas and water produced or disposed at all entry and exit points in a production network. Ideally, the allocation factor should be equal to 1. This means that the measurement of all fluids coming into the system at the various entry points matches the measurements of fluids coming out - correcting for pressure, temperature variations and accounting for mass transfer between phase through proper PVT models. Because of the errors in various measurements, the back allocation factor may differ from 1. Field allocation factors can vary from 0.6 to 1.2, and it is reported (see reference 15) that the worldwide average for well allocation is close to 0.85. In a majority of operations the back allocation is lower than 1, specifically for oil, corresponding to an overreporting of the oil rate made upstream (at the wellheads or at pads). Poor well testing and production measurements can result in improper allocation practices, which in turn can impact reserve management. One of the objectives of developing and deploying the novel multiphase metering techniques is to improve the allocation factor.
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Document ID: DCE33D72

Installation And Operation Of Liquid Densitometers
Author(s): Stan P. Canfield
Abstract/Introduction:
Density is defined as mass per unit volume. Typical units used in the United States are grams per cubic centimeter or pounds per gallon. Densitometers determine the density of a fluid at operating conditions. This density is used in determining the total mass usually pounds for a particular period in time such as the ticket period.
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Document ID: 13AD25AD

Leak Detection On Petroleum Pipelines
Author(s): Bobby G. Moore
Abstract/Introduction:
Leak detection and monitoring on petroleum pipeline systems is becoming more important in day to day operations. Mandates from both regulatory (Integrity Management Rule-permitting for new pipelines) and society (resulting from recent fatal accidents) has reinforced the idea that prudent operators of hazardous liquid pipelines must utilize and maintain the best available technology in detecting and responding to pipeline leaks and spills. With technology and experience making continual advances, pipeline companies are obligated to keep pace with new and better systems. Pipeline leak detection can be broken down into two different types of methodologies internal and external. Both of these methodologies have numerous ways to perform leak detection, each of which provide a different degree of reliability for their type of application. API Standard 1130, Computational Pipeline Monitoring, provides assistance to pipeline operators in identifying issues relevant to the selection, implementation, testing and operation of leak detection systems. Additional information can be obtained from API Publication 1149, Pipeline Variable Uncertainties and Their Effects on Leak Detection, and API Publication 1155, Evaluation Methods for Software-based Leak Detection Systems.
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Document ID: 1B54F537

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. This intent of this paper is to provide basic information regarding the process of odorizing natural gas, which includes characteristics of chemical odorants, typical methods of injecting odorant into natural gas pipelines, and detecting odorant in natural gas. I have sought and used information on areas within this paper dealing with chemical odorants and odorant testing equipment from colleagues whom I consider experts in these fields. You will find them referenced and I urge you to use these references to obtain more information on these critical areas which are so important to the odorization process.
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Document ID: F0F71F5A

Liquid Measurement Field Surveys
Author(s): Wesley G. Poynter, Ph.D.
Abstract/Introduction:
A review of measurement facilities and procedures is often called an audit. This can be confusing, though. The dictionary defines Audit as An official examination and verification of accounts and records, especially of financial accounts. In the oil patch, Audit if often used loosely to describe either or both aspects of a measurement review which includes: 1. A review by Auditors who check to make sure things are done in accordance with established procedures, that calculations are correct, and that the accounting process is current and correct. This is close to the dictionary definition in that it includes, but is not necessarily limited to, examination and verification of records and accounts. 2. A review of field facilities and operations to ensure that proper equipment is used, that equipment is installed in accordance with manufacturers and industry guide lines, that proper measurement/calibration procedures are used, and that personnel are properly trained. This aspect of a review does involve examination and verification, but of equipment and procedures rather than accounts. To differentiate, this aspect will be called a Measurement Survey.
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Document ID: CB6FBB08

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: 7AEBE08B

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 moved from the MMCF to the MMBTU. As technology has advanced, there has been a greater sense of urgency for employee training. The open-access market, which moves greater quantities of gas volumes with considerably lower profit margins, became a reality in the mid- to lateeighties. 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. Current reorganization trends that flatten company structures translate into a leaner workforce. Utilizing fewer employees to accomplish a higher degree of productivity with emphasis on becoming more customer-focused requires a greater training effort. The obvious question to many companies is How do we effectively meet this challenge? An adequate training program is essential to meet the demands of increasing technological advances in the gas industry. Knowledgeable, skilled personnel are a key factor for a company to remain successful and competitive through this transformation process and into the future.
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Document ID: 50A13FC2

Marine Crude Oil Terminal Measurement Systems
Author(s): Jerry Upton
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: 86FC8823

Mass Meters For Liquid Measurement
Author(s): Simon Garner
Abstract/Introduction:
The type of mass flowmeter most commonly used for liquid petroleum measurement applications is the Coriolis principle meter. Patents for Coriolis devices date back to the 1970s and since that time the market has expanded rapidly. It is expected that within the next 5 years Coriolis meters will be established as one of the top 3 metering technologies, along with differential pressure and magnetic flowmeters. The feature of Coriolis meters which makes them so versatile is that they measure mass flow directly and independently of the physical properties of the fluid such as viscosity, temperature or density. They also exhibit metrological performance unmatched by volumetric flowmeters with better than +/- 0.15% accuracy. This performance and the ability of Coriolis meters to lend themselves to a wide variety of applications and fluids fuelled their rapid adoption by the measurement community. Traditionally initial cost has been high, but when correctly selected and installed Coriolis meters have proven to be cost effective and an excellent choice for both mass flow and density measurement. No longer regarded as a high tech, high end solution, newer models are replacing Positive Displacement meters in applications in the Chemical, Food and Pharmaceutical sectors. The Petroleum Industry globally has extensive experience with Coriolis mass flow and many companies are using and continuing to evaluate Coriolis meters. To gain maximum benefit from applying mass flowmeters, the end user must know the relative advantages over other technologies. They must be aware of how the meters can provide value over the lifetime of the equipment, taking into account purchase, installation, operation and maintenance considerations. An ever-expanding variety of products are available and users should be aware of the features offered and relevance to the application. To this end the paper will introduce the theory of operation behind Coriolis meter design and how the mass flow rate measurement is made. What mass flow meters can do and what to look for when selecting an instrument. Applications of the technology in the Petroleum Industry are described with reference to the special benefits mass meters offer. Installation is critical to effective measurement performance and the key points from manufacturers experience are explained. Effective meter proving confirms the accuracy of the instrument during its operating life. Mass and volumetric proving methods are discussed.
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Document ID: 8A7CB17B

The Effects Of Additives On Metering In Liquid Pipelines
Author(s): Joseph T. Rasmussen
Abstract/Introduction:
Todays refined fuels are formulated using a recipe of chemical blending and complex processing. Current blends that make-up fuel & chemicals introduce new problems that challenge product quality and performance. Refined products can be altered or degrade prior use by secondary forces such as environment and handling. A wide range of performance and handling problems are minimized or resolved by use of chemical additives. Additives to fuel products are often included in the refining processes that address these problems. Fuels may require additional blending of additives separate from the refining process. The effect these additives have on liquid metering is variable based on their composition and concentration. Pipeline and terminal metering systems must adjust to the varying properties the additives introduce to the liquid. This paper highlights the effects some common & not-so-common fuel additives have on liquid metering systems.
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Document ID: 140FDD73

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: 376FE1FC

Measurement Losses By Shrinkage
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 a shrinkage. In this paper, only the negative deviations or losses will be addressed.
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Document ID: 42793DA8

The Role Of The Blm In Oil And Gas Measurement An Overview Of Onshore Orders 4 And 5
Author(s): Lonny R. Bagley
Abstract/Introduction:
Onshore Federal and Indian oil and gas lease operations are subject to a variety of legislation, regulations, lease terms, Onshore Oil and Gas Orders, Notices to Lessees, written orders, and other instructions. Not only do many different rules exist affecting lease operators, but these requirements come from multiple sources such as the Mineral Leasing Act of 1920, 30 U.S.C. and the Federal Oil and Gas Royalty Management Act of 1982 (FOGRMA), 30 U.S.C. 1751. The Mineral Leasing Act authorizes the Secretary of the Interior to Aprescribe such rules and regulations as he deems reasonably necessary@ to carry out the Act. Congress enacted FOGRMA, because of concern over the accuracy of the production information submitted by operators to the federal government, especially its impact on royalties. Pursuant to this authority, the Secretary has promulgated rules to regulate oil and gas production on leased federal and Indian land. 43 C.F.R. Part 3160. The Bureau of Land Management (BLM) also has the authority to issue Onshore Oil and Gas Orders, which themselves prescribe additional rules and regulations for onshore oil and gas operations. These Orders are promulgated through APA notice and comment rulemaking and therefore carry the force of law. See 43 C.F.R. 3164.1. This paper will review the role BLM plays in regulating oil and gas operations. Specifically, oil and gas measurement requirements contained in Onshore Oil and Gas Orders 4 and 5. The purpose of these orders, is to establish requirements and minimum standards for the measurement of oil and gas by methods authorized in 43 CFR 3162.7-2,3 and to provide standard operating practices for the lease oil storage and handling facilities. Proper oil and gas measurement ensures that the Federal Government and Indian mineral owners receive the royalties due, as specified in the governing oil and gas leases. These orders are applicable to all Federal and Indian (except Osage) oil and gas leases and all wells and facilities on State or privately owned minerals land committed to a unit or communitization agreement that affects Federal or Indian interests.
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Document ID: 86F89173

Measurement Methods For Liquid Storage Tanks
Author(s): Harold L. Gray
Abstract/Introduction:
A brief discussion on Methods for Determining Volumes in Liquid Storage Tanks. This will include tank gauging methods and errors that can occurr. Tanks strapping methods and pitfalls associated. Methods for determining temperature of the liquid and tank shell temperature. Gravity determination. And finally sampling methods for S&W content and quality of the liquid, for ticketing purposes.
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Document ID: 06AFFAEA

Measurement Of Petroleum On Board Marine Vessels
Author(s): John A. Jack Szallai
Abstract/Introduction:
Marine measurements are, generally, used to confirm the validity of shore side custody transfer measurement from meters or gauging of shore tanks. 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. 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 which permits them to change their orientation relative to a flat plain 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. Marine vessels ARE NOT strapped or physically calibrated like a shore tank. The calibration or ullage tables for a marine vessel are developed from the naval architects drawings rather than physical measurement. Therefore any changes, adjustments and/or mis-alignments in the construction of the marine vessel will not be reflected in the calibration tables. This results in a measurement bias for each vessel. This bias is the basis for the Vessel Experience Factor (VEF) which will be discussed later. Additionally, marine vessels do not maintain a constant orientation, i.e., a shore tank is fixed and built to be level. Admittedly, some shore tanks lean, have bottom flexing, etc. but marine vessels will change vertically (list) and horizontally (be trimmed down by the stern or the head) on a regular basis. Compounding this change orientation is the fact these changes are not consistent. Since the calibration tables for a marine vessel are developed for a vessel being on an even keel (no trim) and upright (no list), adjustments have to be made to the marine measurements when the vessel is not on an even keel and/or upright. Since the marine vessel is constantly going through changes in trim and list these adjustments apply most of the time. Factors such as the vessel resting on the bottom of the channel, twists in the hull, hogging and sagging, or sludge and sediment build-up in the bottom of the vessel will influence marine vessel measurements. In the short period of time allotted we will address the basic measurement procedures outlined in API MPMS Chapter 17 and discussion the influence of the physical limitation of the vessel in obtaining accurate measurements on board marine vessels.
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Document ID: DF262BE3

Operational Experience With Custody Transfer Liquid Ultrasonic Meters
Author(s): Warren A. Parr, Jr.
Abstract/Introduction:
For years the petroleum industry has search for the perfect volumetric measurement instrument. The industry has progressed from using barrels to high speed mechanical devices for measuring petroleum. In the 1990s, several new technologies made their way in to the measurement arena. One of these technologies was the Ultrasonic Flow Meter (UFM). In order to determine the UFMs capabilities, durability, and performance, several companies were asked to perform tests in conjunction with a national standards writing organization. The goals were to collect data to determine if the UFMs could be used for custody transfer applications and to draft a standard for the petroleum industry. In this paper we will review, Basic operation of UFMs. Advantages and shortcomings of UFMs. Recent testing in custody transfer application. The UFMs place in tomorrows measurement
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Document ID: 538059B6

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: AA7F9537

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: 84BD217D

Statistical Control Of Meter Factors - A Simplified Approach
Author(s): R. G. Dodson
Abstract/Introduction:
The role of a measurement specialist is more unique than any other job description in an organization. We dont make policy, but do follow precise guidelines and tolerances as established by law, industry standards, and company policy. While we work for, and are paid by, a specific organization, every job we do positions us in the middle between buyer and seller. Our companies hold either of these definitions at various times. It is incumbent upon us to communicate the results of our work in a clear and concise manner to both technical and non-technical colleagues. Most of us convey this information in writing by memo or letter, and there may be a few who still do this verbally - not a good method in this day and age. There is another way to report measurements that no only shows volume and flow rates, but also demonstrates the health of the metering system. Once established, a meter control chart requires less time than a memo and provides detailed information for various areas of the management and finance team. Unlike the memo or the letter, the control chart is a graphical representation that a non-technical person can understand with little knowledge of the craft. Additionally, the control chart is invaluable to the people actually doing the work on the equipment. This paper will introduce the reader to this powerful, yet simple, tool and encourage its use.
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Document ID: D76224F4

Troubleshooting Liquid Pipeline Losses And Gains
Author(s): Wesley G. Poynter, Joseph T. Rasmussen
Abstract/Introduction:
Todays pipelines are multi-dimensional systems providing multiple services for many shippers and customers. Pipeline systems may connect multiple origins and destinations, and carry various products across long distances with changing profiles, pipe dimensions and directions. Monitoring pipeline 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: FF202CEE

Ultrasonic Meters For Liquid Measurement
Author(s): Christopher B. Laird
Abstract/Introduction:
The first significant application of ultrasonic technology for petroleum measurement was on the leak detection meters on the Alaska pipeline. In this case, sections of the 48 pipe were fitted with ultrasonic transducers forming four chordal paths - see Figure 1. 23 meters were installed along the 800 mile long pipeline. These meters are still in service.
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Document ID: 63D92BE4

Viscosity And Its Application In Liquid Hydrocarbon Measurement
Author(s): Doug Arrick
Abstract/Introduction:
This paper discusses the reasons for wanting to know the viscosity of a hydrocarbon and the some methods for measuring viscosity.
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Document ID: 2FD94E25

Advanced Applications Of Flow Computers And Telemetry Systems
Author(s): Scott Jackson
Abstract/Introduction:
This paper will focus on advanced applications of battery powered flow computers and telemetering of data and control to and from remote measurement sites.
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Document ID: 90FCE43B

Application Of Flow Computers For Gas Measurement And Control
Author(s): Matthew A. Diese
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 onboard firmware, and associated host software, that allows the user to maximize the flow computers versatility and efficiency.
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Document ID: 0E8BDA7B

Applications Of Portable Computers And Software
Author(s): Cameron R. Spitzer
Abstract/Introduction:
Laptops, handhelds, palmtops and PDAs are becoming common in the Natural Gas Industry to perform a variety of portable computer functions. Applying these different technologies to fit a given task is sometimes not immediately apparent. Portable Computers do make the field users job easier to perform, if time is taken to assure that they are selected to fit the application. Emphasis in this paper will be on mobile computing as it relates to the Natural Gas Industry.
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Document ID: 6FFAE558

Basic Applications Of Telemetering Systems
Author(s): Terry Cox
Abstract/Introduction:
Telemetering is the process of transferring data measured, calculated, or monitored data, over a distance or from point A to point B. One of the first forms of telemetry developed was used to determine pressures and flows of natural gas pipelines. It was popular during the 70s and 80s. This type of telemetering used a process known as pulse duration. Pulse duration is a process of a pulse being transmitted over a set period of time to indicate a variable. For example the first times were based on a 3-15 second time interval. A 3-second pulse provided a measure of 0% of scale and a 12- second pulse provided a measure of 100% of scale. Why start at 3 seconds? This provided for a true 0, if the pulse was less than 3 seconds the processor could determine that the value was actually less than 0%. The 15- seconds provided for a true 100%. These pulses were usually passed through dedicated phone circuits to a central point where the data was presented in the form of charts on recorders for monitoring. This was a great improvement over previous operating schemes because it provided real time data. The data accuracy varied however due to temperature and distance of the wiring used for transmission.
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Document ID: 95BBD7D1

Basic Electronics For Field Measurement
Author(s): Dale Gary
Abstract/Introduction:
This paper is written with the idea of presenting basic electronic principles and how to apply these to common applications in the oil and gas industry.
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Document ID: ECEAB49E

Basic Scada Systems
Author(s): Rick Kroeker
Abstract/Introduction:
A SCADA (Supervisory Control and Data Acquisition) system is typical made up of many distributed remote microprocessors that are communicated to (supervised) by a central computer system most commonly referred to as a host. Supervisory control implies that the remote unit performs the local control function with the host performing the supervisory control function such as writing the setpoint to the controller. Not only does the host system send supervisory commands to the remote units but also it usually collects data (data acquisition) from the units. This data can be used for many purposes including feedback to the system operator, trending, alarming and accounting. SCADA systems are used for systems that are dispersed over large geographical areas such as gas, oil, electric, water and wastewater systems. In todays information age, the requirement for timely data is ever increasing. Increased quantity, quality and frequency of data yields better operational efficiency, safety as well as financial benefits. These requirements are imposing and requiring more sophisticated hardware and software, but a SCADA systems still contains the basic components. They can be categorized into the following areas. 1. Field Sensors and Actuators 2. Remote Terminal Units (RTUs) 3. Communications 4. Central Host Computer Systems 5. Data Users This paper will define each of these areas and provide a basic understanding how distributed systems are controlled (supervised) and how data flows from field to the various data users (data acquisition).
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Document ID: 5C507536

Communication Systems For Gas Measurement Data
Author(s): Shawn Kriger
Abstract/Introduction:
The objective of this paper is to discuss the types of communication systems used to collect measurement data from the meter site and to communicate with a central computer. It is targeted to individuals who are looking at designing or adding remote communications to their gas measurement system. The intent is to provide an overview of how a communication system works and operates. We will discuss what questions to ask before designing the sytem. The different technologies available and some of the key areas which effect the overall design, installation and operation of a remote communication system in a gas measurement environment.
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Document ID: 94CC6063

Communication To Measurement Equipment At Gas Distribution Locations
Author(s): Chris Spriggs
Abstract/Introduction:
Deregulation of the natural gas business has increased the number and type of economic decisions being made as well as the number of individuals making them. With the unbundling of services, customers of all sizes are opting to choose their own gas suppliers, and when people need to make choices they demand information on which to base those choices. This new environment has created a widespread need for gas volume information on a more frequent basis to multiple parties. Today, its not just the pipeline companies that need to know the meter readings, but also the customers, brokers, and suppliers. Customers demand for timely information has accelerated gas distribution companies shift to electronic technologies especially involving communications. Little antennas are popping up all around gas facilities. Meters are being read remotely and their data is communicated to a measurement data processing group via many varied communication paths. Oklahoma Natural Gas, has learned that making the change to remote data collection requires a flexible mix of technology solutions, particularly with the variety of existing data collection devices in play.
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Document ID: A03253C1

Flow Computer Applications In Liquid Measurement
Author(s): Rick Heuer
Abstract/Introduction:
Flow measurement of liquids has been around much longer than the measurement of gas. Even so, you would think that it would have evolved at a much faster pace than its counterpart. My guess is that it was much more of a challenge and required more effort to meter gas in the beginning. Liquids seem to have a more finite physical presence. I can always pour liquid into1 gallon containers & then count the containers. We are not so lucky with gas! But due to the complexity of some types of liquids and their chemical composition, metering them can pose to be an extreme challenge. Thus the need for improved metering devices, techniques and technology. Flow computers are designed for these types of tasks. Traditional liquid metering and control requires a turbine or PD (Positive Displacement) meter, Density input, Process Pressure and Temperature. Orifice metering which produces a pressure drop proportional to the rate of flow is common also. The API now recognizes Coriolis and Ultrasonic meters. Coriolis and Ultrasonic meters output a manufactured pulse. The coriolis is a true mass meter and the ultrasonic is a volume meter. These two types of meters also have the ability to communicate to the flow computer by digital communications. Thus providing measurement values along with internal diagnostic capability. Of the many application roles a flow computer works in, they are divided into two groups: ?? Fiscal ?? Operational Fiscal or custody transfer implies that a buying or selling transaction is taking place based on the flow computers calculated volumes. Operational in nature, denotes that its calculations are intended to control or supply input for fluidic process control. Both functions require high accuracy digital resolutions and speed, but only fiscal metering requires that the flow computer meet OMIL, API, and ISO type recommendations or standards. Measurement Technicians and Engineers are required to operate and maintain a variety of Hi- Tech field measurement equipment. Most of the field instrumentation is tightly integrated in a complete System functional environment. The larger the metering station, the more complex the system.
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Document ID: 71F491AB

Economics Of Electronic Gas Measurement
Author(s): Shawn Kriger
Abstract/Introduction:
Electronic flow computers (EFM) or chart recorders? Old technology or new? These are two basic questions energy companies must answer when planning the short and long term goals for the measurement and control of their production, gathering or transmission systems. Many companies have already made the switch to electronics. They are using EFMs on every new field installation. They are also in the process of replacing existing charts that already exist in the field. Other companies have not made the switch. Chart recorders continue to be the main component of their gas measurement systems. 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 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 out of one box. And most important, cost has come down. This paper is targeted at the companies that are currently struggling with the decision to upgrade or make the switch to electronic flow meter technology. The intent is to analyze some of the key areas which will effect overall operations and provide examples of potential economic benefit or loss. These areas include: Initial Up Front Cost Measurement Accuracy Data Flow / Remote Communication Additional Automation Capability Field Maintenance / Training Type of Project Ultimately, a cost-benefit analysis must be made when considering the switch to electronic measurement technology. The cost to operate chart recorders may be less in some areas. However, the benefits of electronics may outweigh these cost in other areas. Some of the benefits will be hidden or intangible, where they cannot be measured in dollars and cents. Other benefits will be clear cut, such as increase in production or the availability of real time data.
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Document ID: 315446E9

Effects Of Cathodic Protection And Induced Signals On Pipeline Measurement
Author(s): James m. Doyle
Abstract/Introduction:
Within the electronic environment of todays pipeline world electronics and electricity sometimes do not go together. Our pipeline systems need cathodic protection to arrest corrosion cells. Our systems also may require other electronic components for acquiring information for Gas Controllers and customers. Metering equipment is always required on our pipelines, and this equipment is becoming more electronically prevalent. When currents from these different types of equipment merge or try to merge, problems will happen.
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Document ID: 5B001643

Ethernet For Scada Systems
Author(s): m. Atwood, E. Estrada
Abstract/Introduction:
The purpose of this paper is to discuss the utilization and installation of Ethernet based communications for the purpose of gathering and distilling plant measurement data. Also discussed are the various pros and cons along with the pitfalls one can expect when installing such a system.
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Document ID: CEEF2F41

Online Computers For Custody Transfer
Author(s): Matthew A Diese
Abstract/Introduction:
With the advent of Electronic Flow Measurement came a variety of calculation, auditing and calibration algorithms. Each manufacturer wrote software to meet either a producers requirement or their own proprietary algorithms. These algorithms, while being effective, were by nature vastly different from one manufacturer to the next. These differences made it necessary to develop a standard for custody transfer meters so that regardless of the manufacturer, the measurement data will be consistent from one meter to the next. This standard became API Chapter 21 - Flow Measurement Using Electronic Metering Systems, Section 1 - Electronic Gas Measurement. API Chapter 21.1 provides the algorithms for all aspects of natural gas measurement for custody transfer. This includes calibration algorithms, calculation methods, historical record content, audit trail considerations as well as installation issues. The standard addresses measurement for orifice and turbine measurement. While ultrasonic meters are not specifically addressed in the standard, it has become customary to treat them as turbine meters for measurement purposes. This paper will focus on calculation algorithms, record management and calibration methods.
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Document ID: F70C22D8

Real Time Electronic Gas Measurement
Author(s): King Poon
Abstract/Introduction:
With natural gas production in the United States peaked and demand rising, natural gas prices will go from 1.50 / MCF in the past decade to 5.00 or more in the coming years. With this in mind, accurate gas measurement is paramount and the delivery of this measurement data must be on time (i.e. accurate real time data). Production, engineering, gas nomination, billing and various administrative functions are just a few of the departments now requiring real time information. Electronic flow computers are now used, instead of charts, by the natural gas industry to automate the data collection and control process. Host computer systems periodically collect data from the flow computers and send control commands, gas analysis data and configuration information to the flow computers as part of daily operations. The success of real-time measurement is the coordination of many functions, including measurement and control, communications, data collection, archiving, post processing, reporting, and the sharing of this information. Breakdowns in any of these functions, affect the integrity of the entire system that prevents the data from being distributed to the end users in a cost efficient manner.
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Document ID: 1B8C6BBA

Spread Spectrum Radio Technology For Gas Measurement
Author(s): Jim Gardner
Abstract/Introduction:
Every year the oil and gas industry deploys more Spread Spectrum communication solutions. As recently as five years ago the telemetry of oil and gas data was almost exclusively in the licensed radio realm. The scarcity of available licensed channels has made Spread Spectrum radio an increasingly popular choice. With the install base of Spread Spectrum devices rapidly increasing there have been a number of Urban Legends or Superstitions & Myths which have started circulating. Among the more prevalent of these are the following. Security---Spread Spectrum is not secure some one can steal your data. Saturation---Spread Spectrum radios will shut down when there are too many radios on the same frequency. Range---Spread Spectrum radios are only one watt and cant perform as well as licensed radios. Compatibility--- if you have licensed radios you have to buy only licensed radios for expansion. Interference--- if you mix licensed radios and Spread Spectrum radios or different brands of Spread Spectrum in the same system they will cause interference and lost data will result. Obstructions--- you have to have clear line of sight, or Spread Spectrum will not communicate. With the advance of any new technology misconceptions and misunderstandings always abound. Spread Spectrum like any technology can be an extremely valuable tool when used in the correct environment. This paper will explore these myths and attempt to provide a better understanding of how to use Spread Spectrum technology and where you can expect to succeed with Spread Spectrum communication solutions.
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Document ID: 630BF808

Pressure And Temperature Transducers
Author(s): Tim Twining
Abstract/Introduction:
Over the past three decades, pressure and temperature transmitters have continuously improved from simple process variable generators to increasingly sophisticated microprocessor-based field transmitters. This continuous improvement has resulted in upgraded device capabilities, including improved device repeatability, stability, reliability, and diagnostics - to name a few. More importantly these device feature improvements have allowed users to change existing plant instrument standards to reduce field device time and effort expenditures. In short, todays better pressure and temperature transmitters have enabled New Best Practices for field device selection, installation, and maintenance. This paper will provide a guideline of these New Best Practices for selecting, installing, and maintaining pressure and temperature transmitters.
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Document ID: 0B0C982A

Testing, Maintenance And Operation Of Electronic Flow Computers
Author(s): Gene Herron
Abstract/Introduction:
The Electronic Flow Computer is now a major component in the gas measurement process. Testing, maintenance and operation are a primary focus for todays field technician.
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Document ID: 3676DD6E

Transient Lightning Protection For Electronic Measurement Devices
Author(s): Patrick S. Mccurdy
Abstract/Introduction:
Technology advances in the world of semiconductors and microprocessors are increasing at a breathtaking pace. The density of transistor population on integrated circuits has increased at a rate unimaginable just a few years ago. The advantages are many: faster data acquisition, real time control, and fully automated factories, to name a few. Semiconductor technology is also prevalent in field mounted instrumentation and electronic measurement devices. Unfortunately, a tradeoff to the increased performance is the susceptibility of these semiconductor devices to voltage and current transient events. The minimum results are unreliable instrumentation readings and operation, with periodic failures. The worst case result is a completely destroyed measurement device. Such power surges are often the work of mother nature. Lightning, which according to the National Weather Service strikes some 40 million times annually in the U.S., is a leading cause of failure in electronic measurement devices. When these devices are field mounted the vulnerability greatly increases due to their remote location and outdoor installation. It should be noted that although the most devastating source of transient voltage and current activity is lightning, there are other sources. Some of these include static buildup, human error, inductive load switching, and utility capacitor switching. This paper explores lightning effects on electronic measurement devices, and methodologies for preventing damage including lightning arrester technology, shielding, grounding and surge protection devices (SPD). The discussion will also cover various coupling methods for transients, and national and international standards that can help in evaluation and application of the proper surge protection network.
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Document ID: 810A4532

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 calibration procedure known as the Water Draw method.
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Document ID: 64D73360

Design, Calibration And Operation Of Field Standard Test Measures
Author(s): Michael J Yeandle
Abstract/Introduction:
Open top, metal, volumetric vessels with a top neck and a graduated scale, traceable to a recognized national calibration agency such as the National Institute of Standards and Technology (NIST), are known as test measures. They are used for the purpose of calibrating liquid meter provers. However, NIST by convention refers to hand held calibration vessels (10 gallons), which are drained overhead, as test measures, and to stationary calibration vessels (10 gallons and 1500 gallons), which are drained by a bottom drain valve, as provers. Since both these types of vessels are used in the waterdraw calibration of liquid meter provers (volumetric tank provers and displacement type proves) the American Petroleum Institute (API) has adopted the convention of referring to both types of standard vessels as field standard test measures. This paper in accordance with popular industry usage will refer to field standard test measures as TEST MEASURES. All test measures must be handled, transported and stored with care to prevent jeopardizing the integrity of their calibrations.
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Document ID: 3270D976

Effective Use Of Deadweight Testers
Author(s): Matt Church
Abstract/Introduction:
The Deadweight Gauge is the most accurate instrument available for the measurement of pressures. Repeatable readings with accuracies of 0.1% to 0.02% of measured pressure are obtainable. The device does not require recalibration unless the components have excessive wear or weights are replaced. It is easily transported and set up in the field, requires minimum maintenance, and is simple to operate. Tripod mounting is available for most instruments. With the addition of a pressure pump, valves, and pressure connections, the hydraulic Deadweight Gauge becomes a Deadweight Tester and can be used to calibrate pressure transducers and other, less accurate dial faced type of pressure gauges. The pneumatic deadweight instruments are testers since they deliver air at an accurate pressure using an unregulated supply.
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Document ID: 8BEE1433

Ultrasonic Meter Flow Calibrations Considerations And Benifits
Author(s): Joel Clancy
Abstract/Introduction:
The primary method for custody transfer measurement has traditionally been orifice metering. While this method has been a good form of measurement, technology has driven the demand for a new, more effective form of fiscal measurement. For most large volume custody transfer meter stations, ultrasonic flowmeters have become the new standard for fiscal metering. Many existing metering stations that use orifice measurement are replacing this with ultrasonic flowmeters. With added emphasis to improve overall measurement uncertainty, most users require flow calibrations prior to installing their ultrasonic flowmeters into their pipeline. Although AGA Report No. 9, Measurement of Gas by Multipath Ultrasonic Meters Ref 1, currently only recommends flow calibration for ultrasonic flowmeters, the next revision will require flow calibration for all ultrasonic custody transfer applications. What considerations then, should be taken when choosing to flow calibrate an ultrasonic flowmeter? What are the benefits to the user? What should a user expect from a flow calibration? What kind of performance should the customer expect or accept from an ultrasonic meter? These areas, as well as others will be explored and considered.
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Document ID: D5A1410D

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: 544E5AC4

In-Situ On-Site() Gas Meter Proving
Author(s): Edgar B. Bowles, Jr.
Abstract/Introduction:
Natural gas flow rate measurement errors at field meter stations can result from the installation configuration, the calibration of the meter at conditions other than the actual operating conditions, or the degradation of meter performance over time. The best method for eliminating these or other sources of error is with in-situ (on-site) calibration of the meter. That is, the measurement accuracy of the field meter station should be verified under actual operating conditions by comparing to a master meter or prover. Field provers have been developed for operation at high line pressures and flow rates. For purposes of this discussion, a high gas flow rate is any flow greater than 3,000 actual cubic feet per hour or (85 m3/h) at pressures to 1,440 psig (10 MPa). A field meter prover may be either a primary flow standard or a secondary flow standard. A primary flow standard is any measurement device that determines the gas flow rate from the fundamental physical measurements of mass (M), length (L), temperature (T), and time (t). Measurement devices based on other techniques or methods are categorized as secondary flow standards. For highest accuracy, a secondary flow standard (sometimes also called a transfer standard) must be calibrated using a primary flow standard at operating conditions. Two comprehensive reports on the subject have been produced by Park, et al.1 and Gallagher.2 Much of the following information is referred to in detail in these reports.
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Document ID: D9B42B66

Lact Unit Proving - The Role Of The Witness
Author(s): Art Casias, Terry Ridley
Abstract/Introduction:
Witness, as defined by the New Websters Dictionary, 1.n, a person who has observed a certain event, the unwilling witness of a quarrel a person who testifies to this observation, esp. in a court of law, and esp. under oath a person who testifies to the genuineness of a signature on a document by signing his own name to the document an authentication of a fact, testimony public affirmation of the truths of a religious faith something taken as evidence, to bear witness to declare, on the strength of personal observation, that something is true to give as evidence, to bear witness, knowledge, testimony. The role of the witness, in the proving of a LACT unit, requires you to understand the operations of both the LACT and ACT units and the device used in proving their accuracy.
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Document ID: 6C4A232B

Liquid Flow Provers Conventional()
Author(s): Harold H. Fisher
Abstract/Introduction:
The purpose of proving a meter is to determine its meter factor, which by definition is a number obtained dividing the actual volume of liquid that passes through a meter by the volume indicated by the meter. The purpose of the meter factor is to correct a meters indicated volume as it pertains to a particular measurement, at a particular flow rate, in a particular petroleum liquid so that the indicated volume becomes a Gross Volume. Therefore, obtaining a meter factor is the first step in calculating the Net Standard Volume of a receipt or delivery of oil.
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Document ID: 4C25A6E5

Liquid Meter Proving Techniques
Author(s): J. H. Harry James
Abstract/Introduction:
Producers and shippers are becoming more and more aware of the importance of accurate measurement. Their bottom line depends on it. As a result, measurement accuracy is being scrutinized more vigorously than in the past. Companies are being required to Verify their metering accuracy. Therefore it is essential that all procedures and auxiliary equipment be operated in a defendable manner. In addition, meters are not always in clean product service and could be subject to severe wear. Even meters in clean service will experience wear over time. To ensure meters give accurate results requires regular precision calibration by a prover operated by a competent individual. Meter proving is the means by which meters are calibrated to provide a factor that can be applied to the metered output that will result in a recorded volume that can be traced back to a regulated standard. This is accomplished by passing an identical volume of liquid through both the meter and the prover. The prover is precisely calibrated using regulated standards.
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Document ID: C8AFC491

Operation & Problems Associated With Prover Detector Switches
Author(s): Warren A. Parr, Jr.
Abstract/Introduction:
In many parts of the petroleum industry, sphere provers are used to dynamically calibrate volumetric meters. In order to accomplish this, sphere provers are required to be accurate and repeatable. This accuracy and repeatability is largely dependent on performance of the prover sphere detector. Any operational or design problems associated with the prover detector will affect the provers performance. This paper will review critical parts of a prover sphere detector that must be checked in order to obtain accuracy reliability and repeatability. The areas that will be covered are: Prover detector accuracy. Prover detector mechanical repeatability. Prover detector electrical repeatability. Prover detector performance due to prover sphere contact length. System accuracy and repeatability.
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Document ID: 320CE01D

Operational Experience With Small Volume Provers
Author(s): Steve Whitman
Abstract/Introduction:
Small Volume Provers (SVPs) were introduced decades ago and are now common technology. There are numerous publications providing empirical data and outlining the technical operation of this equipment. However, the following document will focus on the authors experience, addressing common concerns and questions regarding SVPs.
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Document ID: BF6DF7D9

Proving Coriolis Flowmeters
Author(s): J. W. Sulton
Abstract/Introduction:
A meter proving is a physical test used to determine the accuracy and performance of a liquid meter. By placing a liquid meter in series with a meter prover, which has a known or base volume in such a way that all the liquid measured by the meter is also measured by the prover. The liquid measured by the meter is compared to the known prover volume. This correction is the meter factor. Prover known Volume Meter Factor Meter Reading If the meter factor is greater then 1.0000 the meter is under-registering (reading low). If the meter factor is less then 1.0000 the meter is over-registering (reading high).
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Document ID: 8F62D278

Theroy And Application Of Pulse Interpolation To Prover Systems
Author(s): David Molloy
Abstract/Introduction:
The flow meter has long been established as the industry cash register. With the high cost of producing and the reduced selling price of products, the accuracy of the meter becomes increasingly important to ensure profitability. To this end regular proving of the meter is essential. Liquid meter proving is carried out by placing a Meter Prover in series with the meter under test the prover having a calibrated base volume. Proving of the meter is by comparing the quantity recorded by the meter with the calibrated quantity displaced by the prover.
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Document ID: 4A9E3133

VERIFICATION/CERTIFICATION Of Devices Used In Liquid Meas
Author(s): Anne Walker Brackett
Abstract/Introduction:
In the past the standards from the American Petroleum Institute and the American Society for Testing and Standards provided specifications for instruments and equipment. Simple compliance with these standards is not enough. Therefore, a system of verification and/or certification of equipment used in measurement of liquids is 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: C1F33CCD

Witnessing Orifice Meter Calibrtations And Field Testing
Author(s): Dan Willson
Abstract/Introduction:
Some may ask, is witnessing orifice meter calibrations and field testing still as important in this age and time as it was in the past. There have been many changes in the natural gas industry and with natural gas measurement itself over the past 15 to 20 years. Many companies, both those buying and those selling have seen mergers, acquisitions and reorganization over the past 5 to 10 years. Also technology has changed or improved making the meters more compact, user friendly and able to do more. Many companies, if not most are in the process or have already changed from dryflow to electronic measurement. While both dryflow and electronic meters are good devices for gas measurement, keep in mind that they are only the secondary devices. The meter tube and plate or ultrasonic measurement are the primary measurement devices. Whether it is the first or secondary device, all need to be in the best possible condition and in correct calibration for true and accurate natural gas measurement. With all the changes comes new problems for both the buyers and the sellers. Although there has been vast improvements with electronics, there is always, just as with the old style measurement, the mechanical, human and nature equation to figure in. So yes, witnessing calibrations and field testing is still very important.
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Document ID: F11852FC

Auditing Gas Laboratories
Author(s): David Bromley
Abstract/Introduction:
Most measurement personnel focus their attention on assuring the accuracy of volume determination equipment. Many hours are spent verifying/calibrating AP, DP and temperature transmitters/transducers, inspecting orifice plates and collecting gas samples. These gas samples are sent to a laboratory, analyzed and the results are generally accepted and the data used in volume and energy determination. Have you ever considered the implication of a laboratory that was not accurately determining the true composition of the sampled gas? The potential errors from inaccurate determination of relative density, nitrogen and carbon dioxide have a direct impact on volume calculation while errors in component concentration will impact the energy determination. This discussion will focus on a process that will assure that the gas quality information used both to calculate volumes and energy totals is performing at a high level. Since your samples are usually analyzed at the same laboratory facility, a biased error from gas quality determination can have as much or more impact on revenue than even the largest individual volume exchange stations, because this error is spread across all metering stations. Therefore, improving the performance of a gas analysis facility is critical to your overall measurement accuracy and companys bottom line.
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Document ID: 81A5A6CC

Btu Analysis Using A Gas Chromatograph
Author(s): Steven G. Lakey
Abstract/Introduction:
For custody transfer of natural gas, not only does one need to know the quantity of gas being sold, but also the quality. A small error in gas quality will translate into many dollars when multiplied over large volumes of natural gas. Currently, gas chromatography is the preferred method for determining the quality or heating value of natural gas. The analysis also provides critical data such as specific gravity and compressibility. This paper will cover the basic hardware in a gas chromatograph. The basic theory of chromatography will be discussed, as well as how the heating value is calculated from the analytical results.
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Document ID: D6CD54CA

Chromatograph Applications And Problems From The Users Standpoint
Author(s): Ronald Sisk
Abstract/Introduction:
Natural gas quality measurement requires a variety of instrumentation, only one of which is the gas chromatogaph. The sale of natural gas is performed on the basis of the heating value per unit volume of the gas (MMBtu). For this reason, proper sampling and/or portable on-line instruments is not only needed but is essential.
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Document ID: EE25C29D

Crude Quality - What Is Involved And Why Is Quality Important
Author(s): D. Pat Morgan
Abstract/Introduction:
Crude Quality - What is Involved and Why is Quality Important is a major issue in the petroleum industry today. A Crude Quality Oversight program is designed to monitor the ongoing quality of a crude supply by measuring certain key properties which directly correlate to quality, value and performance. There are many benefits to this type of monitoring program. It: Keeps suppliers honest Allows ongoing valuation of individual crude streams, used in trading crudes for refinery supply Supports refinery operations & optimization efforts Identifies possible contamination sources Supports regulatory compliance efforts
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Document ID: 8F1DAED8

Determination Of H2S And Total Sulfur In Natural Gas
Author(s): Ray N. Adcock
Abstract/Introduction:
Hydrogen Sulfide (H2S) is a gas composed of one Sulfur Atom and two Hydrogen Atoms. H2S is formed by the decomposition of organic matter and is therefore, found naturally in crude oil and natural gas deposits. H2S is a highly toxic, transparent, colorless and corrosive gas. Due to the toxic and caustic properties of this gas and its natural presence within natural gas, it is imperative to measure and control the concentration levels of H2S within natural gas pipelines. This paper will discuss the Properties, Purpose of Measurement and Measurement Technologies for H2S and discuss how these technologies can be adapted for measurement of Total Sulfur.
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Document ID: 85250BEF

Determination Of Water Vapor Content In Natural Gas
Author(s): Borys J. Mychajliw
Abstract/Introduction:
The focus of this paper will be to review the different sensor technologies that are in use today for the measurement of water vapor content in natural gas. We will also address key issues and proper procedures in assembling a sample delivery system to provide a clean, representative gas sample to the sensing device. Natural gas is one of the most widely used fuels today for everything from home heating to power generation and, maintaining the gas quality is of great concern. The determination of the water vapor content in natural gas is one of several key factors in determining the ultimate quality of the gas. With economic conditions as they exist today, many companies have been forced to cut personnel in order to maintain a reasonable balance sheet. The loss of experienced measurement technicians places a heavy burden on instrument manufacturers to provide an accurate and reliable means of making this measurement.
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Document ID: C7B222F5

Determination Of Hydrocarbon Dew Point In Natural Gas
Author(s): Andrew J. Benton
Abstract/Introduction:
This paper considers the requirements for control of hydrocarbon dew point in natural gas and how measurement of this important gas quality parameter can be achieved. A summary of the commercially available on-line instrumentation is provided covering: Manual, visual technique with cooled mirror dewpointmeter. Equation of state calculation from extended composition analysis by gas chromatograph. Determination of liquid to gas ratio of cooled sample flow Automatic, optical condensation dewpointmeter The role of each measurement technology is described and assessed in terms of the effectiveness of the measurement method utilized together with other technical consideration as well as initial and operating cost implications. Full consideration is given to the specific difficulties to be confronted resulting from the complex nature of the parameter concerned. Such peculiarities include the effects of pressure, fractional condensation, the minute proportion of heaviest molecular weight components within the gas composition that contributes to the formation of condensate at the hydrocarbon dew point, and the overall subjectivity of the measurement itself where no absolute reference or definition is possible. A case is presented for the use of advanced optical techniques in an adaptation of the fundamental cooled mirror principle to provide automatic on-line measurement with a degree of objectivity and repeatability unobtainable with other measurement techniques.
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Document ID: 26FEB18D

Determination Of Hydrocarbon Dew Point In Natural Gas
Author(s): Myles J. Mcdonough
Abstract/Introduction:
The hydrocarbon dew point temperature is one of many parameters that must be monitored as a part of controlling the overall quality of the gas. Other parameters that are typically monitored include gas composition, heating value (BTU content), and relative density (specific gravity) just to name a few. The Hydrocarbon Dew Point Temperature in natural gas will vary for a variety of reasons. There are various methods used to control the hydrocarbon dew point temperature in the gas and there are also different instrument types and methods available to measure the hydrocarbon dew point temperature. In this paper, we will discuss the requirement for control of the Hydrocarbon Dew Point in Natural Gas and will summarize the various techniques and devices used for the determination of the Hydrocarbon Dew Point.
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Document ID: 20D726A0

Determination Of Hydrocarbon Dew Point In Natural Gas
Author(s): Borys J. Mychajliw
Abstract/Introduction:
The focus of this paper will be to review the different sensor technologies that are in use today for the measurement of water vapor content in natural gas. We will also address key issues and proper procedures in assembling a sample delivery system to provide a clean, representative gas sample to the sensing device. Natural gas is one of the most widely used fuels today for everything from home heating to power generation and, maintaining the gas quality is of great concern. The determination of the water vapor content in natural gas is one of several key factors in determining the ultimate quality of the gas. With economic conditions as they exist today, many companies have been forced to cut personnel in order to maintain a reasonable balance sheet. The loss of experienced measurement technicians places a heavy burden on instrument manufacturers to provide an accurate and reliable means of making this measurement.
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Document ID: 266456F9

About Ishm 2004
Abstract/Introduction:
Collection of documents about ISHM including table of contents, event organizers, award winners, committee members, exhibitor and sponsor information, etc.
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Document ID: FD0B6DD6


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