Compressibility Of Natural Gas
Author(s): Jeffrey L. Savidge
Abstract/Introduction:
The accurate measurement of natural gas and natural gas related fluids is difficult. It requires care, experience, and insight to achieve consistently accurate measurements that can meet stringent fiscal requirements. It is particularly difficult to measure complex fluid mixtures that are exposed to: (1) a range of operating conditions, (2) dynamic flow and fluid property behavior, and (3) changing equipment conditions. The compressibility factor is a ubiquitous concept in fluid measurement. It is used throughout many measurement practices and standards. At its most practical level, the compressibility factor is another fluid measurement correction factor. Unfortunately the mathematical methods, tools, descriptions and data associated with the compressibility factor obscure much of its simplicity. The purpose of this paper is to provide background on the development of the compressibility factor and related methods. It discusses their use in natural gas measurement, provides examples of the behavior of the compressibility factor, and illustrates the level of uncertainty that current compressibility factor data, methods and related property standards provide
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Document ID:
AD1089A2
Coping With Changing Flow Requirements At Existing Meter Stations
Author(s): Ronald Sisk
Abstract/Introduction:
In todays competitive gas market, it is of paramount importance we focus on change of flow requirements. All industries have cash registers, and gas distribution is no exception. Our measuring stations are our cash register. The problem is, these stations were designed 10, 20, 30 or even 50 years ago, and are now performing tasks they were not designed for. Therefore, changes must be made. Measurement personnel today must be trained and taught to cope with changing flow requirements. But, modifying a station to meet todays aggressive market can be very expensive. Equipment, such as Regulators, Orifice measurement, Coriolis measurement, Ultrasonic measurement and Turbine measurement must meet A.G.A. 3, A.G.A. 7 and A.G.A. 9 requirements. The secondary element (the recording device) can raise expenditures significantly. Sometimes modifications can be made to deliver the specified volume of product needed rather than replacing the complete station to save expenditures. To handle these situations effectively, technicians must be trained to cope with changing flow requirements. Knowing your stations and their characteristics is importance. Technicians must become familiar with the kind of equipment their station has, and its proper use. The goal here is to detail the appropriate methods and equipment required to handle these tasks
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Document ID:
D4832451
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 a safe, effective, and economical unit.
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Document ID:
3308158C
Determination Of Leakage And Unaccounted For Gas
Author(s): David Wofford
Abstract/Introduction:
Leakage and unaccounted for gas volumes are of the most significant costs of operation for natural gas producers, gatherers, processors, transporters and distribution system operators. These operational costs are so significant that such are directly addressed in tariffs, rate case filings and contractual agreements between parties in order that such may be itemized as a cost of operation, equitably managed and responsibly mitigated. Common acronyms denoting lost and unaccounted for gas volumes are LAUF (Lost And Unaccounted For), LUG (Lost and Unaccounted for Gas) and UAF (UnAccounted For). All of these designations refer to the same issue - Product that you believe you should be able to account for but for some reason cannot. For the sake of this discussion, LAUF shall be our acronym of reference. So what is LAUF? It is the difference, or amount of imbalance, determined when performing physical system volumetric, energy or mass balancing analyses. The causes of LAUF are rooted in the inherent uncertainties associated with hydrocarbon measurement, as well as variances and errors that occur within the systems and processes employed to measure, record and calculate volumetric, energy and mass quantities. LAUF issues are quantified within defined categories that comprise a typical pipeline system balancing analysis. Several of the most prevalent are System Receipts, Deliveries, Fuel and Use, Metering and Quantity Calculation Integrity, Line Pack and Variance, Pipeline Retrograde Condensation, Gas Quality, Contaminants and Impurities, and Leakage. While this categorical list captures most of the issues that will arise during system balancing analysis and LAUF mitigation, there are inevitably outliers that creep in from time to time to cause hair-pulling grief for the system operator and balancing analyst. So a bit of advice when it comes to LAUF determination and mitigation - Remain open minded to any and all possibilities!
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Document ID:
9C2CD284
Effects And Control Of Pulsation In Gas Measurement
Author(s): Ray G. Durke Darin L. George Edgar B. Bowles, Jr Robert J. Mckee
Abstract/Introduction:
One of the most common measurement errors and the most difficult to identify in natural gas metering systems is that caused by pulsating flow. It is important to understand the effects that pulsations have on the common types of flow meters used in the gas industry so that potential error-producing mechanisms can be identified and avoided. It is also essential to understand pulsation control techniques for mitigating pulsation effects. This paper describes the effects of pulsation on orifice, turbine, ultrasonic, and other flow meter types. It also presents basic methods for mitigating pulsation effects at meter installations, including a specific procedure for designing acoustic filters that can isolate a flow meter from the source of pulsation.
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Document ID:
D37178A5
Effects Of Abnormal Conditions On Accuracy Of Orifice Measurement
Author(s): Dean Graves
Abstract/Introduction:
Whenever one focuses on gas or fluid measurement, he or she will eventually discover an abnormal condition at a measurement station. Invariably someone will ask, What effect will it have on measurement? A student of measurement may spend years answering this question. This and similar questions have generated many research studies. This research has enabled us to better understand measurement abnormalities and to improve measurement procedures and standards. Even though we have made great strides in measurement, we will continue to ask this question. It is this question that has led to the development of this paper. Instead of focusing on certain specific abnormalities, this paper addresses the overall subject of measurement abnormalities and presents some investigative tools for the reader as they attempt to answer this question. However, before we can understand measurement abnormalities, it is important to review proper or accurate measurement
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Document ID:
F0E00E81
Fundamentals Of Gas Measurement I
Author(s): Douglas 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:
AE04A561
Fundamentals Of Gas Measurement II
Author(s): Jerry Paul Smith
Abstract/Introduction:
A knowledge of the Fundamentals of Gas Measurement is essential for all technicians and engineers that are called upon to perform gas volume calculations. These same people should have at least a working knowledge of the fundamentals to perform their everyday jobs including equipment calibrations, specific gravity tests, collecting gas samples, etc. To understand the fundamentals, one must be familiar with the definitions of the terms that are used in day-to-day gas measurement operations. They also must know how to convert some values from one quantity as measured to another quantity that is called for in the various custody transfer agreements. Below are listed some of the most commonly used terms and their definitions along with some examples of various conversions that must be made from time to time by people working in the natural gas industry
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Document ID:
6AF9DF65
Fundamentals Of Gas Measurement III
Author(s): Joseph J. Bauer
Abstract/Introduction:
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:
95FEAEE3
Fundamentals Of Gas Turbine Meters
Author(s): Paul Honchar
Abstract/Introduction:
The majority of all gas measurement used in the world today is performed by two basic types of meters, positive displacement and inferential. Positive displacement meters, consisting mainly of diaphragm and rotary style devices, generally account for lower volume measurement. Orifice, ultrasonic and turbine meters are the three main inferential class meters used for large volume measurement today. Turbines are typically considered to be a repeatable device used for accurate measurement over large and varying pressures and flow rates. They are found in a wide array of elevated pressure applications ranging from atmospheric conditions to 1440 psig. Turbine meters have also become established as master or reference meters used in secondary calibration systems such as transfer provers. A significant number of both mechanical and electrical outputs and configurations have become available over the past 60 years of production. This paper will focus on the basic theory, operating principles, performance characteristics and installation requirements used in turbine meter applications. A discussion of fundamental turbine meter terminology is also included.
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Document ID:
AE3F07B8
Installation And Operation Errors In Gas Measurement
Author(s): Paul J. La Nasa
Abstract/Introduction:
This paper presents the influence of installation and operation errors in both differential and positive metering gas flow measurement. It takes into account the type of meter, secondary instruments, and the determination of physical properties. The paper then relates this information to measurement accuracy
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Document ID:
05C85043
Low Pressure Gas Measurement Using Ultrasonic Technology
Author(s): Dr. Volker Herrmann Toralf Dietz John Lansing
Abstract/Introduction:
The utilization of ultrasonic metering as a cost effective form of measurement has grown dramatically over the past 10 years. A growing portion of this market is in custody transfer applications. This growth is primarily due to growing acceptance in industry, advances in the technology, extensive self diagnostic capabilities and industry /regulatory standards and recommendations related to their use in custody transfer applications. With the research and development which has been completed to date, ultrasonic meter use in domestic /residential and high pressure applications has been proven and has widespread acceptance. New research and development is being done to address the segment of the market which poses additional challenges in the use of this technology. This is the use of these meters in atmospheric and low pressure applications such as gas distribution systems, and industrial fuel gas measurement
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Document ID:
FB52B379
Mass Meters For Gas Measurement
Author(s): Karl Stappert
Abstract/Introduction:
Since the early 1980s, Coriolis meters have gained worldwide acceptance in gas, liquid, and slurry applications with an installed base of more than one million units. Through significant design enhancements in the early 1990s Coriolis meters have rapidly gained worldwide acceptance in gas phase applications with over 120,000 meters installed worldwide and most notably the 2003 publication of AGA Report Number 11, Measurement of Natural Gas by Coriolis Meter. Having the ability to bidirectionally measure almost any gas phase fluid from -400 to +400 degrees Fahrenheit without concern of error or damage due to flow profile disturbances, pulsations, regulator noise, surges, compressibility change, and density change, Coriolis meters are becoming the fiscally responsible meter of choice in many applications. Coriolis is a medium to small line-size technology currently the largest offering from any vendor for gas applications is a 10 (250mm) flow diameter. The pressure drop and flow range of a Coriolis meter draws a direct relationship to the actual flow area through the meter when comparing it to other metering technologies i.e. the flow area through a turbine meter is the area not displaced by the turbine internals and rotor, the flow area of an orifice meter is that of the orifice diameter. Because of this relationship, a Coriolis meter will typically be one pipe size smaller than a turbine meter and several sizes smaller than an orifice while having similar pressure drops at flowing pressures in the 300 ANSI class and above
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Document ID:
8EBC37E5
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:
ABEF864B
Basic Principles Of Multi-Path Ultrasonic Meters For Custody Transfer Natural Gas Measurement
Author(s): Martin Schlebach
Abstract/Introduction:
In the past decade the use and acceptance of Ultra Sonic Meters (USMs) to measure high pressure natural gas has risen exponentially. Not only has the technology been used in retrofitting or adding stations on existing pipelines, but it was the technology used on most major new pipelines constructed in recent years. There have been several reasons for the increased acceptance, the initial release of AGA report #9 and related standards that deal with the use of USMs in custody transfer measurement. These standards coupled with the meters inherent advantages have propelled USMs to their current level of acceptance. These advantages include no pressure drop, low capital costs for larger sized meters (10), high turndown ratio (80-1) and little or no periodic maintenance. With the decreasing size of most maintenance departments, the ability to lower, even eliminate periodic site visits has become increasingly important. These were huge points of consideration when one of the new pipelines opted to use USMs exclusively, even in smaller sizes where the initial price was higher than other metering technologies, the potential saving in OPEX greatly outweighed the initial CAPEX.
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Document ID:
3FC1DFAE
Orifice Fittings & Meter Tubes
Author(s): Steve Ecklund Matthew Friesen
Abstract/Introduction:
The orifice fitting has been one of the industrys leading methods of measuring gas flow for many years. Based upon Bernoullis Principle that flow can be calculated by forcing fluid through an orifice and measuring the resulting pressure drop, the orifice fitting today offers industry a combination of cost effectiveness, mechanical simplicity and statistical accuracy that makes it attractive for a wide variety of flow measurement scenarios. Over time, orifice fitting and meter run manufacturers have developed improvements that add value and ease-of-use to the end user. However, notwithstanding these and other minor dimensional or tolerance standards revisions, the operative principles of the orifice fitting have changed little over the years
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Document ID:
AA9A67C1
Orifice Meters - Operation And Maintenance
Author(s): Keith Harper
Abstract/Introduction:
The natural gas industry has seen many changes lately. Most of the changes are driven by the supply and demand which interns drives the price. Producers and pipeline companies have seen tremendous growth and reorganize the strong pace required to keep up with the industry needs. Natural gas demands have increased with the more stringent air guidelines pushing all to seek cleaner fuel alternatives including NGC to power our vehicles. This increased demand for natural gas and the logistics involved in acquiring it, motivate us to seek more practical solutions in installation and maintenance of our orifice metering.
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Document ID:
3A78C5AE
Thermometry In Gas Measurement
Author(s): Jorge A. Delgado
Abstract/Introduction:
The temperature in natural gas is dynamic, when gas molecules are compressed they heat up, and as they expand after flowing through a restriction it cools down. Gas temperature it is also affected by external elements such as the temperature of the pipe. It is also good to note that the greater the temperature measurement error, the higher the measurement uncertainty becomes
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Document ID:
9FC7A616
Wet Gas Measurement
Author(s): Richard Steven
Abstract/Introduction:
Demand for wet gas flow measurement technologies has been increasing steadily for many years. As natural gas wells age the once dry natural gas production flow becomes wet natural gas as the dynamics of the reservoir change. Furthermore, with the value of hydrocarbon products rising steadily, reservoirs that were once considered not profitable, or marginal, are being produced. These marginal fields often produce wet gas flows from the outset. It is essential that these wet gas flows are metered as accurately as possible. The traditional method of metering wet gas or multiphase flows is to separate the fluids in a dedicated separator vessel. The inlet of these vessels receives the unprocessed flow of natural gas and liquids (which may be both hydrocarbon liquids and water). The vessel is designed to separate the component fluids and allow the flow to exit separately as natural gas and single component liquid flows where single phase flow measurement technologies can be utilized. This is the original wet gas and multiphase meter technology.
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Document ID:
13D3C946
Flow Conditioning For Gas Measurement
Author(s): Blaine Sawchuk
Abstract/Introduction:
The most important aspects of flow measurement are the flow conditions within the pipe upstream of a meter. Flow conditions refer to: the gas velocity profile, irregularities in the profile, varying turbulence levels within the velocity or turbulence intensity profile, swirl (type I, full body rotation, Type II, complicated multiple axis rotation) and any other fluid flow characteristics which will cause the meter to register flow different than that expected. Installation effects which cause flow conditions within the pipe to vary from reference conditions are: insufficient straight pipe, exceptional pipe roughness or smoothness, elbows, valves, tees and reducers, just to name a few. Certainly, a common understanding of how these installation effects impact the meter is important since devices which create upstream installation effects are common components of any standard metering design. Flow conditioning is explained as well, and refers to the process of artificially generating a reference, fully-developed flow profile for the flow meter, and is essential to enable accurate measurement while maintaining a costcompetitive meter standard design. Industry-accepted nomenclature and discussions are presented which explain commonly referred to flow conditions. This paper is a senior-high level overview of what flow conditioning is and how it can impact meter station design and meter accuracy
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Document ID:
0AFBD256
The Impact Of Greenhouse Gas Measurement How Recent Regulations Impact The Measurement Of Greenhouse Gases
Author(s): Jim Tangeman
Abstract/Introduction:
The regulatory environment affecting the oil and gas (O&G) industry over the last two years has been rapidly changing and expanding. Unfortunately, the majority of regulatory changes have generally not been favorable to the industry. Among these regulatory developments, a key one has been the issuance of the first ever federal greenhouse gas (GHG) mandatory reporting regulation (MRR). The first set of these federal regulations was issued by the US Environmental Protection Agency (USEPA) on October 30, 2009 under 40 CFR Parts, 86, 87, 89 et al. encompassing a large variety of industries across the country. A subsequent set of regulations was issued on November 30, 2010 and this second set of regulations issued under 40 CFR 98, Subpart W encompasses all sectors of the O&G industry from wellhead to burner tip. This paper covers the background of the GHG MRR, the various portions of the rules affecting the O&G industry, and the measurement and monitoring related requirements associated with the latest set of rulemaking delineated in 40 CFR 98, Subpart W (Petroleum and Natural Gas Systems).
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Document ID:
A7D4483B
Measurement And Regulation Operations Of A Ldc The Day To Day Operations Of A Ldc, Including Measurement And Regulation Techniques
Author(s): Ron Carnahan
Abstract/Introduction:
An LDC is an acronym for Local Distribution Company. This refers to one of the links in a long chain of natural gas production and sales which begins in the research, exploration, drilling and production of natural gas wells, and ends with sales to distribution companies and other customers including industrial, commercial and residential. All of the natural gas along this supply chain must be measured with some form of natural gas meter in order to contractually account for the sales to various customers. Also it is very likely that the pressure of the pipelines that connect the various systems together must be controlled with regulators to safely protect the population of the communities and customers who are served. Many papers have been dedicated to the history of gas measurement and principles of pressure control philosophy so this class will not spend much time on these topics (Sargent 2010 American Gas Association 1984). This discussion will focus on the measurement and regulation techniques involved in safe and accurate operation of a local distribution company or LDC.
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Document ID:
A0F9759C
New Differential Meters In Natural Gas
Author(s): Casey Hodges
Abstract/Introduction:
There are several relatively new differential producing meters that are available for end users. Each meter claims to have advantages over other meter types, specifically orifice meters. Meter types discussed include cone meters, Venturi meters, multi-ported averaging pitot tubes, multi-holed orifice plates, and diagnostic differential meters. This paper is intended to be used by purchasers of these meters to help them obtain the best meter for their application. The operating principles of these meters will be explored. This paper will look at the claims that the manufacturers of these meters make in terms of accuracy, required upstream lengths, and diagnostic capabilities. Another important aspect of these meters is industrys reaction to these meters. Should these meters be included in standards documentation? What data needs to be collected to properly develop standards, and what standards exist to help develop these meters? Additionally, the implementation of these meters and metering systems is discussed with the intent of developing system uncertainties. From a calibration facility perspective, many issues have been observed with differential metering systems. Several of these issues will be discussed in detail along with their associated implications
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Document ID:
34ABFB0B
Effects Of Atmospheric Pressure On Gas Measurement
Author(s): Denis Rutherford
Abstract/Introduction:
One of the often overlooked or misunderstood parameters in upstream gas measurement is the atmospheric pressure input. To correctly configure any Electronic Flow Measurement (EFM) device to calculate a corrected volume, the static pressure at the meter run must be input to the calculations as an absolute pressure value. Since the absolute pressure is defined as the sum of the gauge pressure and the atmospheric pressure at the site, proper EFM setup requires that the atmospheric pressure be accurately determined for each metering location. This paper discusses the differences between gauge and absolute pressure sensors, methods of determining the atmospheric pressure at a location, and effects on measurement accuracy. Pressure Defined We need to first understand the concept of atmospheric pressure. Simply put, atmospheric pressure is the force exerted by the weight of the atmosphere on a given point of the earths surface. A standard atmosphere at mean sea level is generally accepted to be 101.325 kPa or 14.696 PSI or 1 ATM.
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Document ID:
02882939
Application Of Densitometers To Liquid Measurement
Author(s): Paul Heinritz
Abstract/Introduction:
Density is the most fundamental element of all physical properties and applies to substances in all three physical states - solid, liquid and gas. Density measurement is a critical component of hydrocarbon instrumentation systems, and inaccurate density measurement can result in the loss of hundreds of thousands of dollars a day. Therefore, understanding the term density, and the instruments that are used by industry to measure density are critical for proper, accurate and consistent measurement. This paper will define density and its units of measurement, theory of operation and physical considerations of a vibrating tube densitometer for liquid density measurement, and proving of a vibrating tube densitometer
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Document ID:
218A0639
Application Of Turbine Meters In Liquid Measurement
Author(s): Mike Bridgforth
Abstract/Introduction:
The purpose of this paper is to provide both novice and experienced measurement personnel with a better understanding of the operating principles and requirements of turbine meters used in liquid measurement applications. Most if not all material herein pertains to the custody transfer measurement of refined products, natural gas liquids (NGL), anhydrous ammonia (NH3), and crude oils. Liquid turbine meters range in size from 1 to 24 in most cases, with some smaller and larger exceptions. Newer turbine meter technologies include the helical rotor design which can be very accurate and less susceptible to the effects of higher viscosity fluids such as crude oils. Newer design electronics offer multiple outputs and can be more immune to electromagnetic interference (EMI) and radio frequency interference (RFI) when properly installed. Turbine meters are available with ANSI pressure ratings from 150# to 2500# making them a practical measurement solution for a variety of applications in the petroleum industry.
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Document ID:
858617AA
Automated Truck Loading Systems
Author(s): John C. Meade
Abstract/Introduction:
Over many years Automated Truck Loading Systems have increasingly evolved into more sophisticated and complex process control and information systems. The design of these ATLSs have brought together emerging technologies in process control and information technology to serve the petro chemical industrys all important mid-stream distribution segment. These emerging technologies have included electronic presets, card and fingerprint readers, programmable logic controllers (PLC), broadband communications, tank-gauging systems, SCADA systems and terminal management software. Terminal management systems or terminal automation software (TAS) as they are often called, have evolved to become the backbone of the ATLS. More and more bulk liquid storage and pipeline companies have come to rely on TAS systems to tightly integrate their ATLSs with their business model and company wide information systems.
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Document ID:
A93A408F
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:
195F7AA7
Crude Oil Blending Ct 2075
Author(s): Brian Betts
Abstract/Introduction:
Blending of Crude oils is a process of mixing two or more crude petroleum components together and is done to improve the overall value or quality of the blend. The reasons vary but may be done to improve pipeline capacity, improve the value of the blend or to help a refinery improve the product yield from its processes. Blending operations can be expensive requiring pumps, meters, tanks etc. Consideration must be given to the cost of infrastructure, cost of diluent, and what measureable property will you use e.g. Viscosity or API gravity. Questions that must be answered include: How will the pay back occur? Will the value of the product be increased? Will the pipeline work more efficiently? Can you blend on someone elses behalf and charge a blending fee? Care must be taken to evaluate all the parameters because one of the blending features may cancel out the benefit initially realized. For example, if two crudes were blended to reduce the overall sulphur concentration the sum of the parts may result in more volume than the pipeline can physically handle. There are a number of applications that require blending of crude oil or other hydrocarbons and they include pipeline capacity, product value and refining efficiency
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Document ID:
688ACF74
Crude Oil Gathering By Truck Metering Versus Manual Gauging
Author(s): J. W. Sulton
Abstract/Introduction:
Normal procedures for custody transfer of oil from lease tanks requires the driver/gauger to manually gauge the producers storage tank to determine the volume of oil in the tank and the S&W content of the oil. This procedure requires the driver to climb to the top of the tank where exposure to H2S or injury from falling from the tank is a risk. This paper will compare the manual method of tank gauging as described in API Chapter 18, Section 1 to the use of a measurement system that is mounted on the transport truck. The truck mounted measurement system relates to a system and a method for measuring crude oil, and more particularly to a system for accurately measuring oil as it is transferred from a lease storage tank to a transport vessel.
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Document ID:
47CE7F4E
Design, Operation & Maintenance Of Lact Units
Author(s): Christopher Levy
Abstract/Introduction:
Reliable hydrocarbon transportation from supply to demand is among the most critical factors in sustaining our way of life. When entering or exiting a transportation network, hydrocarbons are measured for environmental protection and accounting systems. A Lease Automatic Custody Transfer (LACT) Unit is a metering point at a lease or production facility through which hydrocarbons are being measured, while unattended, for sale from one party, such as a production company, to another party, such as a pipeline company. The purpose of the LACT Unit is to determine the volume of hydrocarbons injected into a transportation network. The term LACT Unit is predominantly used to refer to a unit at a production facility that automatically measures crude oil being injected into a pipeline system or storage terminal prior to downstream delivery to a refinery for processing however, much of the content covered in this paper applies universally to hydrocarbon flow metering
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Document ID:
0D25C278
Displacement Meters For Liquid Measurement
Author(s): Darren Heath
Abstract/Introduction:
This paper explores the strengths, weaknesses and inherent design principles that are relevant to positive displacement meters. It will also highlight the parameters to be considered in order to provide accurate meter & meter system selection
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Document ID:
2B8B89CB
Effects Of Flow Conditioning For Liquid Measurement
Author(s): Blaine Sawchuk
Abstract/Introduction:
dichotomy formed and inadvertently turned into standard practice in the flow measurement engineering business. The present school of thought is that there is a distinction between liquid phase and (gas) vapor phase hydrocarbon flow conditioning, metering businesses, and flow measurement for that matter. The distinction is Reynolds Number, not Phase. It is the intent of this paper to begin the process of rectifying this misunderstanding. By educating our industry into the commonality and differences between the two. Computational Fluid Dynamics is utilized to explain commonality along with citing flow measurement standards. It is common in introductory physics to divide materials into the three classes of solids, liquids, and gases, noting their different behavior when placed in a container. This is a handy classification in thermodynamics, for example, because of the strong differences in state relations among the three. In fluid mechanics, however, there are only two classes of matter fluids and non fluids (solids). Copied from Viscous Fluid Flow, Frank M. White, 3rd edition page 15
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Document ID:
88803EE6
Effects Of Petroleum Properties On Pipeline Measurement
Author(s): Jim Smith
Abstract/Introduction:
Measurement of liquid hydrocarbons in most pipelines is done on a standard volume basis or by mass. These dynamic measurement points typically are custody transfer and are the cash register measurements between the two parties involved in the transactions. This is one reason why the measurement accuracy is critical with some others being product accountability and a one time dynamic measurement point. The volume or mass measurements must account for the entire liquid product received or delivered in order to track and determine if product is being lost or gained. Several fluid properties can change the accuracy of this measurement and knowing how they impact the measurement is crucial to its integrity. This paper will focus on dynamic measurement or measurement by metering and discuss several fluid properties and their affects on measured results involving the common types of metering technologies used today.
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Document ID:
3B3D8A9C
Dense Phase Fluid Measurement
Author(s): Fred G. Van Orsdol
Abstract/Introduction:
Many people in the industry, including probably most measurement specialists, have no experience with the measurement of dense phase fluids (if you dont count water). When the un-initiated are asked to develop or operate such a system, they tend to repeat the same mistakes others have made over and over due to trying to treat the streams like natural gas liquids or liquefied petroleum gases (NGLs or LPGs). Hopefully, this paper will assist the un-initiated reader avoid some of those mistakes. Although definitions can be boring, I would like to cover a few that will help the student be sure they understand the fluid properties unique to dense phase fluids and eventually clarify the unique handling these fluids require. Dense Phase Fluids, often referred to as supercritical fluids, by definition, are simply those fluids that are above their critical point at operating conditions
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Document ID:
30872BD5
Evaporation Loss Measurement From Storage Tanks
Author(s): Misty Isaacs
Abstract/Introduction:
Evaporation is the natural process where a liquid converts to a vapor. All liquids have a certain vapor pressure which depends on the surface temperature of the liquid and its composition, both of which impact evaporation. There are many potential sources of evaporation loss in the crude oil industry. One major source, which is the focus of this paper, is from fixed and floating roof storage tanks. In the past, industrys main concern was minimizing evaporation losses to help maximize the bottom line of the company. However, with the growing concern of volatile organic compounds (VOCs) polluting the air and the United States Environmental Protection Agency (EPA) implementing stricter regulations, the need to improve and accurately estimate evaporation losses was inherent. The American Petroleum Institute Manual of Petroleum Measurement Standards (API MPMS) Chapter 19 details equations for estimating the average annual evaporation loss from storage tanks. These equations are based on test tank and field tank data and have been revised since initial publication for more accurate estimations
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Document ID:
92308DA5
Fundamentals Of Liquid Measurement - Part 1
Author(s): David Beitel
Abstract/Introduction:
Correct measurement practices are established to minimize uncertainty in the determination of the custody transfer volume (or mass) of products. Understanding and evaluation of the fundamental cause and effect relationships with the liquid to be measured will lead to a volume determination that most closely matches the true volume at the referenced standard pressure and temperature. When designing a new measurement station it is up to us as measurement people, to understand the product to be measured, apply the correct equipment, and implement the appropriate correction equations
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Document ID:
338B6085
Fundamentals Of Liquid Measurement III - Dynamic
Author(s): Peter W Kosewicz
Abstract/Introduction:
Weve learned when measuring crude oil or any hydrocarbon that liquids expand and contract with increases and decreases in temperature. The liquid volume also decreases when pressure is applied. All these effects are part of the physical properties of liquid petroleum fluids. We learned in Fundamentals of Liquid Measurement I how these physical properties effect the measurement of liquid hydrocarbons. The objective of either static measurement or dynamic measurements is to determine the quantity and quality of hydrocarbons transferred. However these measurements are rarely performed at the standard conditions discussed in Fundamentals I, therefore not only must temperature be measured, but also density, sediment and water, vapor pressure, pressure and viscosity must be measured. With these measurements correction factors such as Volume Correction Factors (VCF) can be determined to allow volumes determined at operating conditions to be expressed at standard reference conditions.
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Document ID:
C685F277
Fundamentals Of Liquid Turbine Meters
Author(s): Dave Seiler
Abstract/Introduction:
Liquid turbine meter design has changed little from the original Potter design developed in the 1960s. Although originally designed for low - accuracy water flow measurement, its application into the aerospace industry called for higher accuracy and reliability as well as simplicity in design. At the same time petroleum and petrochemical industries adopted the meter. With the publication of API 2534 in March 1970, the liquid turbine meter became a recognized meter for use in custody transfer of refined products and pipeline systems as well as tanker and barge loading or unloading of crude oil
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Document ID:
E40C16C1
Gauging, Testing And Running Of Lease Tanks
Author(s): Jane Williams
Abstract/Introduction:
Many production sites do not have metering facilities for custody transfer. Metering facilities require additional capital expenditures but minimize the labor costs over the life of the lease. If metering is not available at the field location the custody transfer measurement is generally performed by manual tank gauging. In this case, after gauging the tank can be emptied into a truck or into a pipeline. Another method which is used occasionally is to have a meter on the truck which serves as the custody transfer. However, the majority of locations which do not have a LACT (Lease Automatic Custody Transfer) Unit utilize the tank gauge as the means of custody transfer. The procedure for gauging of tanks is covered by API (American Petroleum Institute) MPMS (Manual of Petroleum Measurement Standards) Chapter 3 in general and Chapter 18 specifically for tanks gauged from a lease facility and the products trucked. Verification of the equipment utilized in the gauging process against certified test standards which are traceable to the NIST is now required for all of the equipment utilized to gauge the tank.
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Document ID:
71E47D8A
Helical Turbine Meters For Liquid Measurement
Author(s): Kyle Anderson
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:
D3348C9A
Installation And Operation Of Densitiometers
Author(s): Corky Atchison
Abstract/Introduction:
The use of densitometers is widespread over many different industries. These range from food & beverage industries to petro-chemical and pipeline transmission. This paper will cover the installation and operation of densitometers in the petroleum pipeline industry. In this area, the densitometer is used to determine various properties of the transmitted product in the pipeline. They are used to monitor flowing density of non-custody transfers, fluid mix interfaces, custody transfers and other applications. This paper will cover the recommended installation and operation of densitometers for custody transfer applications. We will review the standards for density measurement found in API Standards Chapter 14.8 and 14.6.
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Document ID:
8AA736CE
Leak Detection On Petroleum Pipelines
Author(s): Randall Allen
Abstract/Introduction:
Early interest in pipeline leak detection was probably born of a desire to prevent interruption of fluid delivery in early open conduits carrying water from its source at high elevation to its destination in the valley. As technology improved and wooden, then lead, pipes carried water under head pressure, the consistent behavior of the flow stream at the delivery point provided evidence of good pipeline integrity. Stepping forward many years, fluids have expanded in types and number, as has the cost of fluid loss in terms of its commercial value, damage resulting from its release, and cost of remediation. Hydrocarbons of many forms are transported safely and efficiently by pipelines compared to railroads or trucks over long and short distances. However, on occasions sufficiently rare that they are not expected, leaks occur. Risk analyzers combine the probability of a leak event with the consequences of the event to determine the appropriate course of action to prevent the leak event and to mitigate damages should one occur. The more courageous among us, who believe they have little need for leak detection technology, have occasionally found their risk analysis short-sighted at high cost in dollars, company reputation and increased government oversight
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Document ID:
06DB99BA
Liquid Measurement Field Surveys
Author(s): Miles Chaney
Abstract/Introduction:
A measurement field survey is an examination or research done to verify procedures, practices, equipment use, equipment installation, users training and user understanding of the importance of these things. It can be used to fix a problem or potential problem as well as a health check of the asset. Unlike audits, which are merely done to verify that the companys policies or contractual agreements are being followed, measurement field surveys are done as learning and teaching tools as well. Measurement field surveys can be performed by any qualified person or group, with the objective to understand and/or correct the things that are not satisfactory. We should also remember to give praise for what is being done correctly.
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Document ID:
64955A3B
Liquid Measurement Station Design
Author(s): Roger Thornton
Abstract/Introduction:
liquid measurement station can be as simple as a single meter run allocation measurement or as complex as a multi meter run station with a multi-tasking control system. Regardless of complexity the measurement quality is no better than the quality of the system design. Utilizing a state of the art meter technology will not yield any better results than allowed by the system design. Liquid measurement stations are found in all areas of the hydrocarbon industry from oil production to custody transfer to refining. A heavy emphasis is placed on the accurate measurement of product in each area of the industry. For this reason the design of a measurement system deserves a high degree of focus
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Document ID:
70D94FFE
Marine Crude Oil Measurement Systems
Author(s): Peter P. Jakubenas
Abstract/Introduction:
The accurate determination of quantity and quality of crude oil or refined products transferred from shore to tanker or tanker to shore, or FPSO or FSO to transport tanker is the function of Marine Crude Oil Terminal Measuring Systems. From the measurement data, a Bill of Lading can be prepared and transport costs, taxes, royalties, and customs fees can be computed. Low uncertainty of measurement is essential as each tanker load represents a value of about 100 million dollars. About is not good enough. Precise measurement of quantity and quality is essential. Even errors of + 0.1% represent a significant amount of revenue. In addition to low uncertainty, meter systems offer several other advantages over older more traditional tank gauging methods. Compared to pipeline measurement, these systems tend to be much larger as high intermittent flow rates are required to keep ship loading times reasonable. Specification guidelines for meter systems and associated equipment are presented in this paper
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Document ID:
2F0ACE69
Mass Measurement Of Natural Gas Liquid Mixtures
Author(s): Eric Estrada
Abstract/Introduction:
The purpose of this paper is to review methods for directly or indirectly determining the mass of Natural Gas Liquid (NGL) streams. NGLs by definition are hydrocarbons liquefied by gas processing plants containing ethane, propane, butane, and natural gasoline.
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Document ID:
58478611
Mass Flowmeters For Liquids
Author(s): Frank Grunert
Abstract/Introduction:
The 1980s was the decade where many companies entered the Coriolis market. Some survived, others were absorbed into bigger corporations and some brands disappeared. This was the time when Coriolis was restricted to small sizes, typically to 2 (DN15 to DN50). There was a flurry of activity and development for smaller sizes, typically 1mm to 6 mm in later years, which is still ongoing as new markets are constantly developed and evolving. In the last few years, there has been a new focus on large diameter meters. The typical requirement for sizes of 4 to 12 up to even 16 has been driven by the needs and growing acceptance of this technology in the Oil and Gas industry, particularly for bulk transfer of refined products. With the introduction of the Coriolis meters to almost all markets today this flow technology gained more and more momentum. With growth rates usually above 10% per year the Coriolis technology according to IMS Research will overtake differential pressure flowmeters transmitters as the largest flowmeter market by 2014, having replaced magnetic flowmeters as the second largest market in 2012. What is the Coriolis effect? The Coriolis effect was first discovered by Gaspar Gustav de Coriolis, a French Mathematician, who defined the Coriolis effect as the apparent deflection of a moving object in a rotating system, this is sometimes called the Coriolis force
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Document ID:
8438318F
Measurement Accuracy And Sources Of Error In Tank Gauging
Author(s): C. Stewart Ash
Abstract/Introduction:
Tank gauging is the means used to determine the quantity of oil contained in a storage tank. How the volume is to be used often determines the degree of desired accuracy. If the volume is to be used to quantify a custody transfer movement and money will change hands based on the result, a high degree of accuracy is required but if the volume is to be used only as an operational tool (i.e., is the tank nearly full or nearly empty), a high degree of accuracy is usually not required. If the volume is to be used for inventory control and/or stock accounting, the desired accuracy would be less than for custody transfer but greater than for normal operations. The volume contained in a tank can be determined either by manually gauging the tank or by using an automatic gauging system installed on the tank. Hand gauging of tanks has normally been considered a very accurate method to determine the quantity of oil transferred into or out of a tank. In the United States, most automatic gauging systems have been considered to be less accurate than hand gauging, but there are automatic tank gauging systems available that meet the requirements for custody transfer
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Document ID:
5A6CF668
Shrinkage Losses Resulting From Liquid Hydrocarbon Blending
Author(s): J. H. Harry() James
Abstract/Introduction:
Pipeline integrity balance and custody transfer accuracy have been the focus of measurement specialists since the industry began trading and transporting liquid hydrocarbons. Even with the best volumetric measurement equipment, unaccounted for discrepancies still were occurring. Temperature, pressure and meter factor corrections were not enough to explain these discrepancies. Mathematicians have been telling us for centuries that one plus one equals two. In an ideal world of Newtonian physics this is the case but in the world of volumetric hydrocarbon measurement one plus one is usually less than two. However it can, in rare circumstances be greater than two. As stated in the Dec. 1967 edition of API Publication 2509C regarding the result of blending two different hydrocarbons, If the nature of the molecules of the components differ appreciably, then deviation from ideal behavior may be expected. This deviation may either be positive or negative that is, the total volume may increase or decrease when components are blended. .. Inasmuch as petroleum components contain molecules of various sizes and weights, solutions of two separate components are seldom ideal. Consequently it is to be expected there may be a change in volume associated with the mixing or blending of petroleum components of varying gravities and molecular structure
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Document ID:
F58239AE
Measurement Of Cryogenic LNG
Author(s): Alastair Mclachlan
Abstract/Introduction:
With depletion of conventional oil reserves, natural gas is becoming an increasingly important source of energy for many countries, including the USA. While some of the demand for natural gas can be met by domestic production or pipeline imports, many countries are becoming increasingly dependent on natural gas imports in the form of LNG. One county which is very a potent example of the importance of LNG, is Japan, which currently imports about 97% of its gas in the form of LNG. LNG imports to Japan represent the majority of global trade in the product and are supplied mainly from Indonesia and Malaysia, the worlds top two LNG exporters. Figure 1 below shows the growth in world trade in LNG from 1990 and forecast to 2020, with the majority LNG being imported by the USA and the Asia Pacific region
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Document ID:
A2BB05FB
Measurement Methods For Liquid Storage Tanks
Author(s): Robert Arias
Abstract/Introduction:
This paper will provide, in general terms, an overview of the different technologies available to measure Net Standard Volumes in storage tanks. The Net Standard Volume (NSV) is used as the primary unit of measurement for custody transfer and/or Inventory Control. The Net Standard Volume (NSV) documents the agreement between the representatives of the interested parties (custody transfer) of the measured quantities and qualities of the transferred liquid
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Document ID:
00B1196C
Measurement Of Petroleum On Board Marine Vessels
Author(s): Juri Koern
Abstract/Introduction:
The process that calculates the volume of liquid petroleum loaded onto, or received from, a ship or barge is known as Custody Transfer Measurement. It is important to note that the custody transfer measurement is not determined by a single measurement. A series of measurements are taken, tests are performed and calculations are made before, during and after the transfer takes place in order to reach a Custody Transfer Measurement. The transferred volume is usually determined by calculating the difference between the volume measured before and after the transfer. After gauging, sampling and temperature readings are taken ashore, on the vessel(s) or by a combination of the two, volume quantities may be calculated. Shore volumes are the quantities measured on shore. The quantities measured on the vessel are ship, barge or vessel volumes
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Document ID:
416B5667
Orifice Meters For Liquid Measurement
Author(s): Fred Van Orsdol
Abstract/Introduction:
Orifice meters have been in common use for many decades, but in the energy industry their use has been primarily in gas metering systems. This is interesting, in that much of the research to develop orifice meter factors (discharge coefficients) has been performed using oil, water, steam and air - as well as natural gas. Orifice meters used in liquid measurement systems provide good accuracy without the requirement for meter proving as long as they are properly designed, installed, calibrated and maintained. If higher levels of accuracy are wanted, they can be proven using appropriate software and hardware and traditional meter proving systems
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Document ID:
4E69E3F8
Pycnometer Installation, Operation And Calibration
Author(s): Paul Mullen
Abstract/Introduction:
This paper will discuss pycnometers used to calibrate densitometers. In using a pycnometer, you must have the correct scales, pressure gauges and thermometers. You will learn the steps necessary to install, operate and calibrate the instrument
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Document ID:
AE1A133B
Resolving Liquid Measurement Differences
Author(s): Jim Godbolb
Abstract/Introduction:
Before we begin a discussion resolving liquid measurement differences, lets take a quick and very basic look at what measurements are, and why they are so important to our industry. Websters defines measurement as: 1) the act or process of measuring 2) a figure, extent, or amount obtained by measurement. Mr. Webster could not have given us a better description of what we do as petroleum measurements technicians. Our job is to obtain an accurate amount, or measurement, of a liquid using a process of measuring. The process used could be hand gauging a tank to determine liquid level, or using a turbine meter in a pipe line system to determine the amount of a liquid moved. We often say that measurements are the cash register of the industry. Lets take a closer look at what is meant by measurements being a cash register.
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Document ID:
AE80A21E
Statistical Control Of Meter Factors - A Simplified Approach
Author(s): Dan Comstock
Abstract/Introduction:
Statistical control is a tool for discernment and communication. This paper will give a brief overview description of a simplified method for monitoring the performance of a flow meter and performing the same exercise on each meter in the system. The idea is to provide graphical assistance, through the use of meter factor control charts in: (a) developing preventive maintenance programs (b) heightening awareness of alarm situations, and (c) reducing risk to the financial bottom line. Meter factor control charts and logs make it easier to prepare reports to maintenance, operations, financial and executive managers from time to time and furthermore, they make it easier for the target audience to digest the points being made.
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Document ID:
958CB616
Troubleshooting Liquid Pipeline Losses And Gain
Author(s): Joseph T. Rasmussen Michael R. Plasczyk
Abstract/Introduction:
Todays pipelines are multi-dimensional systems providing multiple services for many shippers and customers. Pipeline systems may connect multiple origins and destinations, and carry various products across long distances with changing profiles, pipe dimensions and directions. Monitoring pipeline losses and gains employs tools and analysis methods developed specifically to troubleshoot pipeline variances. Examination of pipeline losses and gains uses basic statistical tools as well as intuitive and creative insight into what controls losses and gains. The basic tool for evaluating system performance is Loss/Gain, a measure of how well receipts, deliveries and inventory match up over a period of time. The concept is similar to that used for leak detection, but usually covers a longer time period. Loss/gain is a measure of the quality of the overall measurement in a system, and excessive loss/gain can signal the need for an investigation to identify causes and develop corrective actions. Good measurement can be enhanced by continuously monitoring the system, equipment and procedures to insure they are operating within acceptable limits. This monitoring may be accomplished by the use of Control Charts. This paper will review control charts and procedures, which may be used to monitor systems, and offers troubleshooting guides to use when a pipeline systems loss/gain is out of tolerance
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Document ID:
A1ECF01C
Ultrasonic Meters For Liquid Measurement
Author(s): Nicole Gailey
Abstract/Introduction:
Petroleum products bought and sold on the worldwide market may be transported over thousands of miles and change ownership many times from the well head to the end user. Each time the product changes ownership, a custody transfer is completed and both buyer and seller expect their asset share to be accurately measured. The dynamic measurement provided by meters is a convenient and accurate means to measure valuable petroleum products. Selecting the right meter for the job with a high level of confidence is imperative to ensure accurate measurement at the lowest the cost of ownership
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Document ID:
28A86A2C
Viscosity And Its Application In Liquid Hydrocarbon Measurement
Author(s): Gary Rothrock
Abstract/Introduction:
The why and how of measuring viscosity in hydrocarbons. Why do you do it? The cost involved and the pros and cons of different ways of doing the measurement
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Document ID:
6EF6F1D4
Measuring High Viscosity Liquids With Flow Meters
Author(s): Kyle A. Anderson
Abstract/Introduction:
There has been a continuous increase in the demand of heavy crude oil due to the price and availability. This trend is expected to accelerate with increasing demand for petroleum products due to the expansion of the world economies and the reduction in light low viscosity crude oil reserves. As a result of this trend crude oil transporters, pipeline and marine, are gearing up to handle a wider range of heavy crude oils. The accurate measurement of high viscosity crude presents new challenges, though. Each of these applications is different and no one type of meter is best for all applications. Fortunately we have a wider range of metering technologies to address these applications
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Document ID:
585CA70C
Field Experience With Coriolis Meters
Author(s): Bynum Vincent
Abstract/Introduction:
Coriolis meters have been successfully utilized in the hydrocarbon markets for well over 20 years. It has only been in recent years that widespread acceptance of this technology has been realized with more and more companies embracing and installing Coriolis meters. To some degree, there has been a learning curve that most everyone has had to go through in order to successfully deploy these meters in their installations. The intent of this paper is to share some of the experiences gathered over many years to facilitate easy deployment and give some general ideas as to how to manage these meters successfully in the field
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Document ID:
770070B1
Accuracy Diagnostics Of Liquid Ultrasonic Flow Meters
Author(s): Joshua W. Rose
Abstract/Introduction:
Liquid ultrasonic flow meters are not new to the measurement of crude oil, but over the last decade technology improvements have enabled liquid ultrasonic meters to meet the higher accuracy requirements needed for custody transfer measurement. The transit time principle of measurement has opened a window to allow observation and measurement of aspects of the flow stream that have never been visible to traditional measurement technologies such as PD meters and turbine meters but are critical to the proper operation of a liquid ultrasonic meter. This paper will discuss the specific diagnostic capabilities of the FMC Ultra6 liquid ultrasonic flow meter and how this information can contribute to maintaining high accuracy custody transfer measurement
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Document ID:
9F7615E5
Offshore Liquid Fpso Measurement Systems
Author(s): Alastair Mclachlan
Abstract/Introduction:
Floating production, storage, and offloading systems (FPSOs) receive crude oil from deepwater wells and store it in their hull tanks until the crude can be pumped into shuttle tankers or oceangoing barges for transport to shore. They may also process the oil and in some later FPSOs to be used for Gas distribution. Floating productions systems have been utilized in remote offshore areas without a pipeline infrastructure for many years. However, they have become even more important with the push by the offshore industry into ever deeper waters. Floating production, storage, and offloading/floating storage and offloading (FPSO/FSO) systems have now become one of most commercially viable concepts for remote or deep-water oilfield developments. They also allow a company to develop offshore resources quickly between discovery and production. They have been shown to reduce this time as much as two to four years. Further there can be significant cost savings in developing marginal fields
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Document ID:
D7030CE4
Applications In Liquid Measurement Using Clamp-On Ultrasonic Technology
Author(s): C. Tim Guest
Abstract/Introduction:
Clamp-On ultrasonic flow meters (UFMs) have been in use by various industries for flow measurement for about three decades. When Clamp-On UFMs were first introduced to the industrial market in the mid 1980s, they were primarily applied in the Water & Waste Water Industry. In those early days Clamp-On UFMs primarily used Doppler technology, whereas modern Clamp-On UFMs predominately utilize Transit Time technology. As the accuracy, repeatability, and reliability of these meters improved over the years, the acceptance of Clamp-On UFMs in the Oil & Gas Industry has grown. Today Clamp-On UFMs are becoming widely used in a variety of critical non-custody applications in the Oil & Gas, Hydrocarbon Processing, Chemical Processing and other industries
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Document ID:
B3BF9980
Measurement Of Liquefied Petroleum Gases Lpgs()
Author(s): Paul Mullen
Abstract/Introduction:
Liquefied Petroleum Gas (LPG) is defined as butane, propane or other light ends separated from natural gas or crude oil by fractionation or other processes. At atmospheric pressure, LPGs revert to the gaseous state. This paper is intended to provide an overview of metering systems used for the volumetric measurement of LPGs. Operational experiences with measurement systems that degrade the performance of these systems will be addressed. It includes information for turbine and positive displacement meters used in volumetric measurement systems. The basic calculations and industry standards covering volumetric measurement will also be covered.
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Document ID:
BAF27232
Viscosity Compensation Of Helical Turbine Meters
Author(s): Nicole Gailey
Abstract/Introduction:
Helical rotor turbine meters can provide significant performance advantages over conventional rotor turbine meters for crude oil service. The use of viscosity compensation (also referred to as Universal Performance Curve Compensation or Viscosity Indexing) and the concept of Dynamic Similitude allows the application range of helical turbine meters to be extended even further
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Document ID:
078F01C3
Advanced Diagnostic Measurements And Verification With Coriolis Flow Meters
Author(s): Timothy J. Cunningham
Abstract/Introduction:
Coriolis flowmeters provide precision mass and volumetric flow and density measurement. The electronics needed for these measurements can be leveraged to provide diagnostic outputs to track and trend measurements and the processes in which the meters are used. This paper discusses these diagnostics. Coriolis flowmeters can be proven like any other type of flowmeter. Proving can be costly and difficult in some processes. Because of this, several techniques to verify the measurement of the Coriolis meter have been devel-oped. This paper discusses, compares, and contrasts these techniques. To better understand diagnostics and verification, Coriolis theory is first presented to provide background under-standing
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Document ID:
C92E25FC
Ngl Terminal Operations And Measurement
Author(s): Blake Stinson
Abstract/Introduction:
Surely one of the most difficult liquid petroleum products to store, handle, and measure with accuracy is natural gas liquid, or NGL. Historically thought of as a nuisance byproduct, many companies within the petroleum industry once ignored this product and the attention to detail that it requires. With todays ever expanding natural gas production, increasing volumes of NGL are demanding further consideration. In addition, as each penny of the industry becomes pinched, more companies are realizing the profit and extended cash flow that NGLs can produce. Natural gas liquids present several obstacles when trying to store, transport, and accurately measure the product. Most of the components that make up natural gas liquids are in a gaseous state at atmospheric conditions, and thus create the largest misunderstanding of the product
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Document ID:
780A5E17
Master Meter Prover Certifications Per API Mpms 4.9.3
Author(s): Scott P. Iverslie
Abstract/Introduction:
The basis for accurate metering of hydrocarbon liquid is directly related to the calibrated volume of the displacement prover used to prove the meter and determine the applied meter factor. Any error introduced during prover calibration results in the same error being applied to the meters being proved. Depending on the volume of the metering system, just a small error can add up to thousands of dollars being lost (or gained) very quickly. Prior to mid 1970, the only accepted practice for prover calibration was the Waterdraw Method found in the American Petroleum Institute (API) Manual of Petroleum Measurement Standards (MPMS), Chapter 4, Section 9, Part 2. Confidence in the accuracy of this method was accepted and promoted by the experts in the oil industry. With the advent of the Trans Alaska Pipeline System (TAPS) in 1977, it became evident that the Waterdraw Method of prover calibration could be very difficult and expensive to perform on TAPS. With the large prover volumes, the number of provers in the system, the remote locations, the availability of equipment and resources for cleaning, the difficulty of disposing large volumes of contaminated water and the desired frequency of calibration all posed significant challenges
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Document ID:
D4EDFE84
Advanced Application Of Flow Computers And Telemetry Systems
Author(s): Rick Heuer
Abstract/Introduction:
Flow Computers are the vital command center for flow metering and control of liquid and gas hydrocarbons. What started out as simple means to measure volumes of fluid, has developed into a vast array of application management.
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Document ID:
CE3BE808
Application Of Flow Computers For Gas Measurement And Control
Author(s): David Savells
Abstract/Introduction:
Electronic gas flow computers are microprocessor-based computing devices used to measure and control natural gas streams. There are a variety of configurations available from dedicated (integrated) single board computers to PLC-based multi-run (hybrid) systems
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Document ID:
7AAFED17
Basic Application Of Flow Computers And Telemetry Systems
Author(s): Martin Johnson
Abstract/Introduction:
Flow Computers have long been used as the cash register for both Hydrocarbon liquid & gas measurement. One of the first microprocessor based flow computers was the 7900 series introduced by Solartron back in 1975 and whilst the functionality of these early flow computers was limited, their primary function has remained the same for the last 30 years or more to accurately compute the amount of gas or liquid that has flowed through the associated flow meter(s).This amount may be expressed in terms of actual volume but is usually required to be calculated in either standard volume (expressed at a given temperature and pressure such as 14.696 psia and 60oF or 1013.25 mBarabs & 15oC ), mass or energy, while adhering to the required National & International Standards The essential inputs to the flow computer are typically flow (volume or mass), pressure, temperature and often density or fluid composition. The essential outputs are the afore mentioned flow totals, which traditionally would be printed in a daily report at a
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Document ID:
8B0610D3
Basic Electronics For The Field Technician
Author(s): Christopher Levy
Abstract/Introduction:
Electronics is the branch of physics, science, engineering, and technology dealing with electrical circuits that are controlled by electrical means rather than mechanical means. The main purpose of electronics is the processing and communication of information and signals. Vacuum tubes were one of the earliest electronic components when electronics technology was known only as radio technology due to the primary application. Today, electronics is driven by micro-sized devices such as transistors and diodes to form the integrated circuit. In comparison, about 400 X 1017 transistors could fit into the space occupied by a single original vacuum tube. The microscopic size of electronic components make todays complex and powerful devices handheld realities. Device size is now limited by power and input/output interfaces rather than logic and computational electronics. As electronics are in almost every currently manufactured electrical device, electronics are certainly a critical element of measurement devices and systems. As technology changes at an ever increasing rate, the need for a technician to understand electronics also rapidly increases with time. Regardless of the size and application of electronics all electronic components are electrical devices and operate according to the basic laws of electricity discovered long ago. This paper briefly discusses electrical safety, some electronic basics, and how electronics is applied to the field of hydrocarbon measurement
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Document ID:
A1FB7173
Scada Systems Graphical Display Design
Author(s): Ian Metcalfe
Abstract/Introduction:
Graphical displays are a fundamental part of a SCADA system and arguably the most used part of a SCADA system. They are the interface between the people that use them and the computers that they exist on. They represent the processes of our real world systems that SCADA systems monitor and Control. The design of these graphical displays is important to the people that use them. Poorly designed graphical displays can easily lead to misinterpretation of information, errors in response and in some cases compromise of system assets that can lead to system failure, injury or even loss of life. 49CFR calls upon API 1165, Pipeline SCADA Displays, to implement standards in the construction of graphical displays to avoid poor design and consequently poor use of graphical display. These standards are discussed in this paper
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Document ID:
816B88A0
Communication Systems For Gas Measurement Data
Author(s): Clay Danley
Abstract/Introduction:
Communications systems for gathering gas measurement data may require the use of several technologies for reliable communications back to the host computer. Commonly used wireless technologies are licensed radio, non-licensed spread-spectrum radio, and cellular because they allow for two-way poll response messages to be passed between the host computer and the end devices such as flow computers and gas chromatographs. Deployment and maintenance of licensed and non-licensed radio systems usually require a fair amount of engineering. Cellular modems are much easier to deploy as they work off of existing cellular infrastructure. Other technical considerations include saturation points, host protocol versatility, and solar power
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Document ID:
B956E51E
Economics Of Electronic Gas Measurement
Author(s): Jesse Green
Abstract/Introduction:
The economics of upgrading to electronic measurement devices versus the older technology of chart recorders are dependent on many factors. For a production company, the principles Safety, Production, and Profitability are keys to making sound business decisions. The use of electronics can in some cases be an effective investment for all three principles. The cost, reliability and expandability of modern flow computers have seen major improvement from when they were introduced in the early 1980s. Todays flow computers offer software and hardware to not only measure gas production, but also control and enhance it. Chart recorders still offer an inexpensive and reliable way to record flow. We will compare the economics of each from an oil and gas production viewpoint. Some key points include the following
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Document ID:
FC36871A
Production Equipment Effects On Gas Measurement
Author(s): John Mcdaniel
Abstract/Introduction:
The drill bit penetrates a rock formation thousands of feet below the surface of the earth, a steel casing is slid into the hole, and perforations are made to the casing that reach into the surrounding rock. At that point, an escape route is created for anything in the formation that can be released to the surface, which has lower pressure, or that can be lifted by that process. The producer must be able to obtain enough of what comes up to the surface and conditioned to a marketable state to make it worthwhile. Obviously, the natural gas, natural gas liquids (NGLs), crude oil and condensates are the valuable commodities that are produced and sold. Unfortunately, other materials are included in what surfaces from inside the earth. Many of these require production equipment to remove the material or condition the product for sale, and the effects of some types of production equipment used can have an effect on measurement
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Document ID:
A122FEDC
Effects Of Cathodic Protection And Induced Signals On Pipeline Measurement
Author(s): Peter P. Jakubenas
Abstract/Introduction:
The effects of cathodic protection and other induced signals on pipeline measurement equipment can be quite profound. This paper will explore the sources and effects of induced signals, and the prevention of undesirable induced signals in custody transfer measurement equipment
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Document ID:
2F276203
Ethernet For Scada Systems
Author(s): Denis Rutherford
Abstract/Introduction:
This paper will cover the implementation of Ethernet applications in SCADA system communications and architecture. Supervisory Control and Data acquisition (SCADA) systems provide a superior base for better controlled facilities in the upstream, midstream and pipelines for oil and gas facilities. Computerized handling of remote installations is integrated with communications and provides means for reducing the operating cost, cost of maintenance and effective handling of the Oil and Gas network. System parameters communicated via wireless data network must present true conditions related to the status of the field equipment including the Custody Transfer Measurement Systems. In likewise manner, commands sent to remote sites must be promptly executed and the back indication is to be sent to the control center. SCADA systems have evolved through three generations of architectures as follows
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Document ID:
6087F637
On-Line Flow Computers For Liquid Custody Transfer
Author(s): Brent H. Palmer
Abstract/Introduction:
A flow computer is an electronic computational device which implements the required algorithms to turn the raw data received from flow meters to which it is connected into volumes at base conditions. A flow computer also audits changes that have been made to any of the parameters required to turn the raw flow meter data into volumes. It records events and alarms related to the flow meter (for example, loss of flow, loss of required electrical signals from measurement transducers, or transition of these electrical signals near their upper or lower range). It will keep a running tally of the volume for each flow meter it monitors and perform a total of this volume on an hourly, daily or monthly basis. The flow data is made available externally through an electronic interface so that other computers can download the information for the purposes of supervision, accounting or auditing
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Document ID:
C8E93F46
Spread Spectrum Radio Technology For Gas Measurement
Author(s): Ben Hamilton
Abstract/Introduction:
Spread Spectrum Radio (SSR) products are in wide spread use by the Oil & Gas industry as well as countless other applications. The quality, performance and cost of communications equipment continue to improve. The FCC allocated a generous portion of the radio spectrum for unlicensed use by this technology. We are becoming increasingly dependents on wireless. Everything from our car key, garage door opener and cordless phone or internet relies on SSR. How does it all work, and furthermore, what allows all these services to avoid conflict with each other? Should the Oil & Gas industry invest precious resources of money and time in a product that is unlicensed and shared by so many other applications? What are the risks, how are we to know if it will meet our needs, how long can we depend on it and how do we know it will work for us before investing in it? These are important concerns that need answers. The ISHM committee gave me the assignment to write this paper and cover these topics: Security, Saturation, Range, Compatibility, Interference, obstructions and advancements in the technology. This paper focuses on the products in common use by the Oil & Gas Industry. I am drawing my observations from not only the physics but also a life time of experience with wireless communications systems
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Document ID:
4D7FD9F3
Smart Transmitter Selection, Calibration And Installation
Author(s): Leon Black
Abstract/Introduction:
Transmitter selection can be summed in general terms under a heading of application. Even though generically speaking pressure transmitters are all the same, the fitness of use for transmitters is not the same. The total accuracy statement of a transmitter that has been hardened to withstand extreme corrosive effects will not appear equal to a reference class transmitter. This kind of information is not within the scope of a transmitter data sheets and there in resides a challenge for users. The history of oil and gas measurement has followed directly the advances made in transmitter technology. As close as 10 years past total sight error budget of 3 - 4% was more the norm than the exception. The transmitters used were for the most part analog and did not have the repeatability or stability to support data where sight requirements were more stringent. Few of these sights were capable of meeting the TEB1 over temperature and even fewer of the locations were able to meet the TEB when over pressure effects were added to the requirements
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Document ID:
927F8D7A
Transient Lightning Protection For Electronic Measurement Devices
Author(s): Leon Black
Abstract/Introduction:
We have all heard of or seen the devastating effects of a direct lightning burst. Communication equipment destroyed. Transmitters and EFM devices vaporized into slag metal. Complete process and measurement systems down with extended recovery times. These effects are the most dramatic and the easiest to trace. However, these kinds of events are rare. The more prominent events are those that occur on a day-to-day basis without we, the user, even knowing. With the advent of the transistor and today when surface mount electronics is the norm and not the exception, transient suppression has become a science of necessity. Tight tolerances of voltage requirements and limited current carrying capabilities makes the new compact integrated circuits much more susceptible to many types of transients.
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Document ID:
6CF9C1CC
Host Gas Measurement Audit Trail Data Handling And Maintenance Techniques
Author(s): Steve May
Abstract/Introduction:
Host Gas Measurement Systems are a requirement in todays business for any company involved in the production, gathering, distribution, transmission or processing of natural gas. In this paper, we will discuss what a Host Gas Measurement System is, what it does and the requirements. We will also discuss some of the maintenance issues around the ever expanding requirements for measurement data, how this is handled in the real world and the reporting requirements for the data. And finally, we will talk about some example applications that are available on the market today
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Document ID:
AA9EF045
The Evolution Of Data Collection For Gas Measurement
Author(s): Dan Steele
Abstract/Introduction:
Evolving communication technologies are revolutionizing SCADA (Supervisory Control and Data Acquisition) systems just as new technology in drilling and production are revolutionizing the way oil and gas wells are produced. The new high volume pad wells and horizontal production techniques demand: ? Faster data collection ? Systems that provide more detailed information ? Greater polling speed ? More remote control ? Ability to optimize production to lower operating costs ? Equipment that is lower cost and easier to install than ever before In todays oil and gas environment, production volumes are many times greater than they were just 10 years ago. The price of these resources is down significantly from where it was in 2008 so, for producers it has become increasingly more important to run more cost-effective operations
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Document ID:
8A5587E9
Calibration Of Liquid Provers
Author(s): William R. Young Jr
Abstract/Introduction:
A meter prover is used to calibrate custody transfer meters to establish a meter factor. The volume that passes through the meter is compared to the prover volume during the time taken for a sphere or piston to pass between two detector switches. The prover volume must be accurately determined by a calibration procedure known as the Water Draw method
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Document ID:
CD0EF754
Effective Use Of Deadweight Tester
Author(s): Roger Thomas
Abstract/Introduction:
One of the most difficult problems facing the instrument engineer is the accurate calibration of pressure or differential pressure measuring instruments. The deadweight tester or gauge is the economic answer to many of these problems. This paper describes methods to select deadweight testers and gauges. Also included are procedures for using pneumatic and hydraulic deadweight testers
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Document ID:
2B3434B6
Guide To Trouble Shooting Problems With Liquid Meters And Provers
Author(s): Brian Pierce
Abstract/Introduction:
The purpose of this paper is to familiarize those involved with the Measurement and Troubleshooting of Proving Systems commonly used in the Measurement Industry. Due to the demand and consumption of Hydrocarbon Products, the need to accurately Measure these volumes, is becoming more prevalent by the day. With the high volumes being produced in Deep Water Drilling, and Pipeline Transfers, its understood by everyone in the Measurement Industry that a small error in volumes of Single Phase Hydrocarbon Measurement can be a significant lost in Revenue. Due to the time allowed for this class, we will discuss Trouble Shooting Problems with Liquid PD Meters and Conventional Bi-Directional Provers in Hydrocarbon Measurement. We will also briefly discuss the importance of designing and installing the LACT components correctly as a measure of trouble shooting problems.
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Document ID:
901E46A9
In-Situ On-Site() Gas Meter Proving
Author(s): Edgar B. Bowles, Jr. Adam Hawley
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:
E3927163
Lact Unit Proving - The Role Of The Witness
Author(s): C. Bynum Vincent
Abstract/Introduction:
transported via pipeline or tanker truck from production facilities to pipeline systems, which transport the product to the refinery for processing. Once processed, the liquids are once again sent via tanker truck or pipeline to the distribution points downstream. Whether these fluids are purchased or consigned to common carriers, there is transaction called a custody transfer conducted to transfer ownership of the product for transportation or distribution. In each of these instances, a representative from each party involved in the custody transfer transaction is generally present to observe or witness the events of each transaction. With a hand run transaction, both parties witness the measurements taken of the contents of tank being sold. Usually, the production operator takes measurements of the tank and writes a ticket and places it in a box. Later, the truck driver dispatched to load the oil from tank takes measurements and compares them to those taken by the production operator. If they match within a certain tolerance, the tanker truck hauler signs the ticket and accepts the custody transfer and loads the oil into his truck
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Document ID:
19FC165A
Liquid Flow Prover
Author(s): Alexander Ignatian
Abstract/Introduction:
The liquid flow Provers have been used as a calibration tool for flow meters in petroleum industry for many years. This paper will discuss the history, technology and proper use of mechanical displacement Provers
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Document ID:
1730E2A2
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. Not only does this relate to the actual product value, but in relation to environmental considerations it also has implications associated with regulatory compliance. As a result, measurement accuracy is being scrutinized more vigorously than in the past. Companies are being required by their clients and regulatory bodies to Verify their metering accuracy. Therefore it is essential that all procedures and auxiliary equipment be operated in a consistent and defendable manner. Metering installations vary vastly in their installation and regular maintenance requirements subject to the severity of service they are subject to. The type of products being handled and the temperature and pressure at which they are operated all play into the requirements. Even meters in clean service (refined products) and normal pressures and temperatures will experience wear over time. To ensure meters give accurate results and to compensate for any wear, or changes to the environmental conditions, requires regular precision calibration by a meter prover operated by a competent individual
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Document ID:
18E441B5
Operation & Problems Associated With Prover Detector Switches
Author(s): Warren A. Parr, Jr.
Abstract/Introduction:
In many parts of the petroleum industry, sphere provers are used to dynamically calibrate volumetric meters. In order to accomplish this, sphere provers are required to be accurate and repeatable. This accuracy and repeatability is largely dependent on performance of the prover sphere detector. Any operational or design problems associated with the prover detector will affect the provers performance. This paper will review critical parts of a prover sphere detector that must be checked in order to obtain accuracy reliability and repeatability. The areas that will be covered are
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Document ID:
8FEA42C2
Operational Experience With Small Volume Provers
Author(s): Kevin Fields
Abstract/Introduction:
The following document will focus on experiences working with the Small Volume Prover and addressing common questions and concerns. Small Volume Provers (SVPs) have become the standard in most custody transfer applications. Today, there are over 500 SVPs located throughout the US and abroad. Over 25 years ago, the first Small Volume Prover was put into service. The Small Volume Prover can be used on multiple fluids and over a wide range of flow rates. One of the most common reasons for choosing a Small Volume Prover is its compact size and large flow rate capacity. Todays SVP can handle rates from 0.01 gpm to 18,000 BPH. With a SVP sized to handle 18,000 BPH, the total prover volume is approximately 120 gallons
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Document ID:
CA388852
Theory And Application Of Pulse Interpolation To Prover Systems
Author(s): Galen Cotton
Abstract/Introduction:
Here we take an in-depth look at the use of Pulse Interpolation as it applies to reduced volume provers (captured piston provers in current API parlance), or Small Volume Provers (SVP) and the implicit in reliability of the technique where the fundamental conditions implicit in its use prevail
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Document ID:
A7F8F451
VERIFICATION/CERTIFICATION Of Devices Used In Liquid Measurement And Implications Of How Mercury Issues Will Impact These Processes
Author(s): Anne Walker Brackett
Abstract/Introduction:
In the past the standards from the American Petroleum Institute (API) and the American Society for Testing and Measurement (ASTM) provided specifications for instruments and equipment. Simple compliance with these standards was not enough. Therefore, a system of verification and/or certification of equipment used in measurement of liquids was instituted. These requirements were written into the standards as they came 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 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 the requirements to insure the instrument and the equipment meets the specifications of each standard. It is important to understand the definitions of traceability, verification, and certification before discussing the specifications for equipment used in liquid measurement.
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Document ID:
32FE16ED
Witnessing Orifice Meter VERIFICATION/CALIBRATION
Author(s): Jack W. Chisum
Abstract/Introduction:
The business of witnessing, verification and calibration of orifice measurement of natural gas is a business that is of significant monetary value to your company. The witnessing of the natural gas being purchased from your company is the most valuable job you can pursue on the companys behalf. Your protection of their assets allows you to make a living from the monies they gain from your actions. A good start, when assigned the task of witnessing, is to find the contact name of the person responsible for the maintenance of the site to be tested. That initial communication is beneficial in insuring everyone is on the same page and there are no misunderstandings as to a time suitable for all parties involved. You may be sent a test schedule that has already been arranged for the site however, verification of the time and place is good business practice. This allows everyone involved to know they are to meet at a prearranged time and place. Summarily most technicians that you work with will be open to adjustments if his schedule allows. Once a time is setup it is your responsibility to be sure you either attend at the designated time and place or give ample notice you cant be present. This will keep from wasting the time of the technician and your companys money
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Document ID:
BE63AD7E
Improving Flow Measurements With Improved Calibration And Data Handling Procedures
Author(s): Duane Harris
Abstract/Introduction:
The knowledge base from a field measurement technician to the measurement analyst is extremely demanding. Every field technician is tested in both knowledge and skills on a daily basis regarding: ? Electronic controls to pneumatic controls ? Communication system support ? Multiple technical disciplines ? Support of measurement equipment ? Procedures that must be followed (SOP) - Standard Operating Procedures ? Regulatory requirements governing the facilities ? Ongoing training of field personnel These factors and many more create a tremendous and constant challenge for every organization
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Document ID:
41810B21
Proving Liquid Ultrasonic Meters
Author(s): Dave Seiler
Abstract/Introduction:
The use of liquid ultrasonic meters for liquid petroleum applications such as custody transfer or allocation measurement is gaining worldwide acceptance by the oil industry. Ultrasonic technology is well-established, but the use of this technology for custody transfer and allocation measurement is relatively new, and users often try to employ the same measurement practices that apply to turbine technology. There are some similarities between the two approaches, such as the need for flow conditioning and upstream and downstream piping requirements, but there are also differences, like the proving technique or field validation procedure. This paper will discuss the various in-situ proving methods that can be used for successful field calibration of a liquid ultrasonic meter
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Document ID:
10882942
Preparing A Prover For A Water Draw Calibration
Author(s): Herb Garland
Abstract/Introduction:
The key to a successful calibration of a prover by the water draw method is thorough planning and organization followed by good execution of the plan. The primary goal is to get the prover as clean as possible and perform any replacements and maintenance needed prior to the arrival of the Calibration Company. This paper is intended to assist you attain an accurate calibration by presenting some things to consider for the planning, organization and execution phases
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Document ID:
3CBAA485
The Uncertainty Of A Waterdraw Calibration Vs. A Gravimetric Calibration On Small Volume Provers
Author(s): Gary Cohrs
Abstract/Introduction:
The focus of the API Petroleum Measurement Manuals is to reduce the uncertainty and improve the accuracy of all petroleum measurements. Many recent advances in weighing equipment and research and testing by various groups to improve volume calibrations have provided opportunities to greatly reduce the uncertainty and provide increased confidence in displacement Prover calibrations. API and NIST have standards on both volumetric and gravimetric techniques. The purpose is to review the history, techniques, similarities, advantages and disadvantages, and the uncertainty comparison between gravimetric and the traditional water draw method of Prover volume calibrations by NIST certified volumetric field test measures, focusing on high precision captive displacement flow Provers, known more commonly as SVPs. Groups, such as American Petroleum Institute Manual of Petroleum Measurements Chapter 4.9.4, and NIST SOPSVP15Nov-06 have defined standards for gravimetric displacement flow Prover calibrations
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Document ID:
0A9D9239
Auditing Gas Laboritories
Author(s): Joe Landes
Abstract/Introduction:
The data produced by Gas Chromatograph (GC) laboratories is used for many purposes, including product specification, accounting, safety and environmental compliance issues. The accuracy of this data has direct impact on all of these areas. Auditing laboratories responsible for producing this data is prudent business practice. The audit will provide a means of process improvement, through proper identification of deficiencies and a precise plan for corrective action. The level of confidence in analytical results will increase when the appropriate corrective actions are implemented. The amount of financial and legal exposure can be reduced from a properly executed audit program
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Document ID:
5DBB0254
Btu Determination Of Natural Gas Using A Portable Chromatograph
Author(s): Russell L. Thomas
Abstract/Introduction:
This paper is meant to introduce new users to portable chromatography and reinforce collection theory and technique to existing users. It is intended to supplement rather than replace or divert existing practices in determination of BTU by portable methodology. Understanding and implementing proven sound engineering and operating practice improve reliable data acquisition and reporting. With the shift of natural gas pricing from a volume basis to an energy basis1, accurate and reliable composition based energy calculation has never been more important
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Document ID:
25FA55C5
Chromatograph Applications And Problems From A User Standpoint
Author(s): Fred Ryel
Abstract/Introduction:
Chromatographs are available for all types of applications in the natural gas industry. The main applications that this class will discuss are: process monitoring of liquids and gases, environmental flares and ambient air, landfill gas and contaminates. These can also include corrosives such as H2S, CO2 and O2, etc. Regardless of the application, the main priority is to capture an accurate sample and not change the properties before it can be analyzed. Maintaining the sample integrity is by far the most difficult process. The procedure of acquiring the sample and the way it is analyzed depends upon the media being sampled
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Document ID:
BF4C1373
Chromatograph Maintenance And Troubleshooting
Author(s): Fred Ryel
Abstract/Introduction:
Welcome to the 87th International School of Hydrocarbon Measurement. This class is going to cover several points that are not necessarily what is called the Chromatograph. This paper is mostly referring to the online Chromatographs but can apply towards a lab or portable analyzer as well. As with the use of any analyzer, the analysis is going to be only as accurate as the sample that is supplied. This is how I start just about all the classes or training I present. It really isnt the Chromatograph but is just as important as any component on the chromatograph. Please feel free to interject with relevant ideas or examples pertaining to what is being discussed at that time. I most always learn something new or different with each presentation or training I do. Most of my experience with chromatographs is with the Daniel and ABB NGC. Although I have worked with other makes on a limited basis. Chromatograph components vary a little with each application and manufacturer. We are going to try and cover the most common components of TCD (thermal conductivity detector) chromatographs. This is the most common type of online gas chromatograph being used in the natural gas pipeline industry
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Document ID:
6B099BCE
Chromatographic Analysis Of Natural Gas Liquids
Author(s): Joe Landes
Abstract/Introduction:
The analysis of natural gas liquids has become an integral part of the measurement process. Two methods that are commonly used in the gas industry to provide this analytical data are the GPA Standard 2177, Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Gas Chromatography and the GPA Standard 2186, Method for the Extended Analysis of Hydrocarbon Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Temperature Programmed Gas Chromatography. The purpose of this paper is to provide an overview of the standards and the steps needed to obtain accurate results
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Document ID:
41395751
Crude Quality - What Is Involved And Why Is It Important?
Author(s): Harry N. Giles
Abstract/Introduction:
Historically, crude oils were traded on the basis of name and a relatively limited number of characteristics such as their API gravity and total sulfur content. Recognizing these were inadequate for determining quality of commingled crude oils in a common carrier pipeline system, the American Petroleum Institute (API) published a white paper in 1993 recommending certain tests to help ensure quality and guard against contamination. These included organo-halide compounds, boiling point distribution, metals, and neutralization number. Today, over 1600 streams are produced and, of these, perhaps 400 are in world commerce - many of which are imported into the U.S. With this large number of crude oils available to U.S. refiners and with their wide range in characteristics, it is imperative that the API recommendations - at a minimum - be used in characterizing a streams quality. This is essential to optimize refinery runs and to assess the concentration and identity of contaminants that may be present
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Document ID:
CDF9DD31
Determination Of H2S And Total Sulfur In Natural Gas
Author(s): Marshall T. Schreve
Abstract/Introduction:
Hydrogen Sulfide (H2S) is a chemical compound comprised of one Sulfur atom and two Hydrogen atoms. It is a colorless and extremely poisonous gas that smells like rotten eggs. Hydrogen Sulfide is highly corrosive and will attack carbon steel, making the pipe or operating equipment very brittle. (Sulfide Stress Cracking) Hydrogen Sulfide is formed when animal and/or vegetable matter decompose in the absence of air (oxygen). Hydrogen Sulfide is commonly found in natural gas and crude oil. Due to the corrosive and toxic properties of Hydrogen Sulfide, it is important to measure, monitor and control the concentration levels in natural gas streams. The purpose of this paper is to discuss the properties, hazards and methods of analyzing for Hydrogen Sulfide and Total Sulfur
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Document ID:
A7F024F3
Determination Of Water Vapor Content In Natural Gas
Author(s): Sam Miller
Abstract/Introduction:
This is an overview of the main approaches to trace moisture measurements for natural gas. Natural gas presents a situation where the stream may have high levels of solid and liquid contaminants as well as corrosive gases present in varying concentrations. Additionally, the stream composition may change gradually or rapidly over time. This unique situation is a challenge for the measurement of moisture
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Document ID:
3B44D475
Hydrocarbon Dew Point Effects On Gas Flow Measurement
Author(s): Fred G. Van Orsdol
Abstract/Introduction:
The hydrocarbon dewpoint (HCDP) of interest to the natural gas industry is simply an operating condition that causes liquids to condense out of the gas stream and form a liquid phase. Normal condensation occurs when increasing pressure or decreasing temperature causes liquids to form. Retrograde condensation occurs on a different portion of the phase envelope, wherein increasing temperature or decreasing pressure may cause the gas to cross the phase boundary and produce condensation. Both processes produce liquids condensing out of gas phase streams and are of interest to this presentation. Phase diagrams will not be discussed further in this paper, other than to mention that present correlations to predict phase behavior have proven to be inaccurate for relatively rich gas streams and typically predict HCDP temperatures well below the actual HCDP temperature. I will try to characterize rich gases, as referred to in this paper, by indicating those at or above 1050 Btus per cubic foot and containing some C4 thru C6+ components (butanes thru natural gasoline).
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Document ID:
9DA1A27E
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
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Document ID:
33860B17
Energy Measurement Using Flow Computers And Chromatography
Author(s): Burt Reed
Abstract/Introduction:
The means and methods of transfer of quantities of natural gas between buyers and sellers have been changing for many years. When coal gasification was used to fuel the streetlights in Atlanta, Ga. There was no reason to even measure the commodity. The municipality generated the gas, transported it, and burned it. When Frank Phillips started purchasing gas rights back in the 1930s, every one thought he was more than odd. Natural Gas was considered at that time a messy by-product of oil production that had to be disposed of. Even during the 1960s natural gas was still being flared at the wellhead in Oklahoma. During the 1940s, it was said that one could drive from Kilgore, Texas to Tyler, Texas at night without turning on the head light on your car due to all the gas flares. In this economic environment, measurement was not an issue if you could sell the gas at all it was considered a business coup. Even then, a good price was 2 cents an MCF. But when Henry Ford was building the Model T, gasoline was a refinery waste product that the heating oil manufacturers were glad to get rid of. Not so now. So, as with other cheap forms of energy, both the use and the infrastructure for natural gas grew.
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Document ID:
225C6A07
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 transport and dispose of. Consequently, monitoring of the sediment and water content is performed at the production site to prevent excessive sediment and water from 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:
7BD52268
Fundamentals Of Gas Chromatography
Author(s): Ulrich Gokeler
Abstract/Introduction:
Chromatography is an analytical technique to physically separate constituents in multi component mixtures with the purpose of quantification. Quantification of specific constituents is the actual objective of chromatography. Unlike other analytical techniques such as spectroscopy, chromatography physically separates targeted constituents from each other or interferences prior to actual quantification. Chromatography is one of the most widely used analytical techniques. It is applied in the laboratory environment, as portable devices or for on-line and automatic measurement. This paper discusses gas chromatography, particularly automatic on-line or process gas chromatography. Although it is important to understand that a gas chromatograph is a part of an on-line and automatic separation system which includes sample extraction, sample transport to and from analytical system, sample preparation and data communication, this paper concentrates on the gas chromatograph only. Described here are the fundamental aspects of gas chromatography, from the actual separation to column switching configurations and from carrier gas to detectors. The fundamentals are particularly focused on the separation and quantification of natural gas constituents and the determination of its physical properties
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Document ID:
079A3480
Flare Measurement Practices
Author(s): Wil Camara John Chitty
Abstract/Introduction:
There has been an increased awareness by oil and gas companies in North America toward emissions monitoring and reduction for both environmental and economical reasons. For years, several countries worldwide have had stringent regulations in place. Regulations were implemented in 1993 relating to the measurement of fuel and flare gas for calculation of CO2 tax in the petroleum activities on the Norwegian continental shelf. Inevitably, oil companies operating in the region had to comply with these regulations
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Document ID:
4EE1A6B5
Heat Quantity Calculation Relating To Water Vapor In Natural Gas
Author(s): Edgar B. Bowles, Jr. Darin L. George,
Abstract/Introduction:
Natural gas often contains some amount of water, in either vapor or liquid form. The solubility of water in natural gas flowing through a pipeline is a function of the pressure and temperature of the flowing stream. The amount of water affects the heating (calorific) value per unit volume of natural gas. The more water present in the gas, the less valuable it is as a fuel, since the water displaces the hydrocarbon components in a natural gas mixture and does not burn. This water, in vapor form, is sometimes referred to as spectator water. The net effect is a reduction in heating value and monetary value per unit volume of gas. The amount of water vapor contained in a natural gas mixture is customarily expressed in terms of the mass of water per unit volume of gas, for example, pounds mass of water per million standard cubic feet of natural gas (lbm/MMscf). If water is present in natural gas that is to be transported, a decision must be made as to whether or not the water should be removed. There is obviously a cost associated with removing and disposing of water extracted from natural gas. Even if the water is left in the gas to avoid the removal costs, there are still other costs involved with not removing it. Because the water has mass, it requires energy (or compression horsepower) to transport. Another important consideration is that water is one of the constituents that can cause corrosion in the steel pipes used to transport natural gas. Repairing or replacing corroded pipelines can be a significant expense. In addition, corroded pipelines may degrade operational safety and system reliability. There are also issues associated with how water adversely affects the combustion process when natural gas is used as a fuel
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Document ID:
380DFEFC
Validating Laboratory Gas Analyses
Author(s): Fred G. Van Orsdol
Abstract/Introduction:
What do you do I someone asks you to determine whether or not natural gas analyses are accurate? Do you panic? Do you use the same sample procedure your co-worker has been using for 30 years? Ordo you refer to API Chapter 14.1 and do it correctly?
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Document ID:
D4848B95
On Line Water Measurement Devices In Liquid Service
Author(s): Kam Mohajer
Abstract/Introduction:
In todays competitive energy market there is a tremendous emphasis on cost saving and productivity at all levels of the industry. Online water detection provides vital real-time information regarding water concentrations in hydrocarbons empowering the user with the knowledge necessary to maximize efficiencies and cost savings while increasing many safety factors at the same time. The installation of On-line Water Detectors or OWDs (also called Water Cut Meters) in pipeline or bypass analyzer loop systems has obvious key benefits at any stage involving custody transfer. With todays high crude oil prices, paying for shipped water is a hugely punitive and now unnecessary cost to energy companies. But OWDs can improve, automate and optimize several other key stages leading to refined materials. Chief among those are production and tank water draw automation
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Document ID:
A8320E83
Sampling And Conditioning For Natural Gas Containing Entrained Liquids
Author(s): Josh H. Welker
Abstract/Introduction:
Wow! The world of sampling and conditioning for natural gas really becomes turbulent when entrained liquids or a two-phase fluid is incorporated. Entrained liquids in a gas stream inherently invoke a battle that those in the measurement industry must not ignore. On one side of the battle is the desire for repeatable, reliable equipment that was most likely designed to sample the wonderful clean, dry natural gas of the world. A very important sector of this side is to include the achievement of real-time billing through online analysis. The other side of the battle is the obligation to pull a REPRESENTATIVE sample of the flowing stream to bill for the correct quality of product
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Document ID:
0DEE9AF6
Sample Conditioning And Contaminant Removal For Water Vapor Content Determination In Natural Gas
Author(s): Brad Massey
Abstract/Introduction:
The Natural Gas Industry experiences numerous operational problems associated with high water vapor content in the natural gas stream. As a result several problems are experienced such as, equipment freezes, dilution of physical properties reducing heating value, volume measurement interference, and pipeline corrosion. Contracts and Tariffs usually limit the amount of water vapor content allowed at the custody transfer point. For these and other reasons, accurate Water Vapor Dewpoint measurements are critical measurements for all companies involved in natural gas production, gathering, transmission and delivery. The industry continues to experience problems in obtaining accurate water vapor dewpoint measurements, primarily due to interference problems associated with contaminants and poor sampling techniques. Various types of analytical equipment are being used to determine Water Vapor Dewpoint Measurements. All are susceptible to contaminate interference or poor sampling techniques being utilized. Proper design and utilization of the correct type of sample conditioning devices or improved sampling techniques will provide much more reliable results, regardless of the equipment being utilized
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Document ID:
167AED03
Techniques Of Gas Composite Sampling
Author(s): Matthew S. Parrott
Abstract/Introduction:
While inaccuracies in measurement are costly and common, they are also avoidable in many cases. Technicians willing to dive into the experiences and best practices of industry leaders can make a world of difference by applying what theyve learned and by sharing this knowledge with others. Composite sampling is not magic. In fact, its surprisingly straightforward. A composite sampler is able to take small bites of a product flowing through a pipeline in such a way that it accurately represents that product for a given sample period. Composite sampling continues to be a widely used method for economically and accurately collecting a representative sample for a prolonged sample period, so it is important for technicians in the field to develop an understanding of the best practices.
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Document ID:
F0035D5E
Techniques Of Gas Spot Sampling
Author(s): Jane Williams
Abstract/Introduction:
This paper will discuss the various approved methods used for spot sampling in the natural gas industry. Proper sampling technique is extremely important because it impacts both the quantity and quality of the gas being measured. Up until 1978 when congress passed the Natural Gas Policy Act, natural gas was sold based on volume. The Natural Gas Policy Act implemented selling of natural gas based on the energy available in the gas being sold. Consequently, the importance of sampling to determine the BTU content of the natural gas sold became much more important. The energy available in a gas stream is the product of the volume and the BTU content of the gas sold. In order to determine the BTU content of the gas, a sample must be captured and analyzed by a gas chromatograph or calorimeter. Typically, the industry utilizes gas chromatographs to make this determination. The sampling method is frequently a function of the volume of gas sold over the period. If the volume sold is small the technique used is usually the spot sampling method, which is the method covered in this paper. In spot sampling, the sample is obtained and transported to a laboratory for analysis by a gas chromatograph. If significant volume is transferred over the period, a composite sample might be utilized and analyzed. This method is more expensive and thus requires more volume. When very large volumes are measured, an online gas chromatograph is justified. Today, an online gas chromatograph can provide a complete C6+ analysis in approximately four minutes. However, the cost of the system is high, which is why it is only utilized at significant volume locations.
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Document ID:
80660800
Fundamentals Of Sampling Natural Gas For Btu Determination
Author(s): Donald P. Mayeaux
Abstract/Introduction:
This paper discusses the fundamentals of extracting, conditioning, and transporting natural gas samples for on line BTU analysis. INTRODUCTION It has long been recognized that the largest source of error in the analysis of natural gas is the sample conditioning system (SCS). The sample conditioning systems consist of all components through which the sample gas travels from its source, typically a pipeline, to the gas chromatograph (GC) inject valve. The purpose of the sample conditioning system is to extract a natural gas sample that is representative of the source, transport it to an on line gas chromatograph, and in the process condition it so that it is compatible with the analyzer
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Document ID:
60E6C2EA
Determining Hydrocarbon Dew Point Per Gas Chromatographic Analysis And Equations Of State
Author(s): Shane Hale
Abstract/Introduction:
The determination of the hydrocarbon dew point (HDP) for natural gas has recently become a critical issue for the natural gas industry because of the rapid expansion of interconnecting pipelines and the rise of the liquefied natural gas (LNG) as an international source of natural gas. Whereas previously the gas in a pipeline would come from a small number of known producers, the gas flowing through the pipeline today could have come from many varied sources including traditional gas plant producers (de-hydration, CO2, H2S and N2 control and removal of condensates), coal bed methane producers (98% methane), low cost producers (de-hydration only) or global exporters of LNG. Economic factors have also played a role in the changing quality of the gas. Unfavorable natural gas/NGL product price spread historically have resulted in HDP concerns for pipeline operators as producers who previously have stripped the heavier components out of the gas to produce condensates have realized a greater return by leaving the higher energy value heavy components in the export natural gas. In todays environment, the spread is very large so producers are focusing on extracting rich-gases (especially in the shale-gas plays) to remove the NGLs in the process and during process upsets rich gas may be sent through to the natural gas pipeline.
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Document ID:
ED6C7769
Reducing Measurement Uncertainty In Process Gas Quality Measurements
Author(s): Charles Cook Ken Parrott
Abstract/Introduction:
Uncertainty is an ever-present and universal flaw in observation. Any statement of measurement uncertainty should be free of subjective terms and should not require interpretation but rather it should only require understanding. This paper will not be able to state a quantification of uncertainty but rather it will offer suggestions to aid users in avoiding uncertainty.
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Document ID:
54D240E6
CO2 Determination In Natural Gas Streams
Author(s): Murray Fraser
Abstract/Introduction:
Carbon Dioxide (CO2) is commonly measured at processing plant outlets and meter stations where Gas Quality contracts limit diluent concentrations in Natural Gas to less than 3-5%. CO2 and Nitrogen (N2) are both considered diluents in Natural Gas as they do not contribute to the heating value. CO2 can be measured in Natural Gas Streams with on-line process analyzers using one of two analytical methods. This paper will discuss the advantages and disadvantages associated with each method. Emphasis will be on principal of operation and the practical issues associated with reliability and maintenance in Natural Gas Field locations. The two methods discussed in this paper are Gas Chromatography and Infrared Spectroscopy using one of two types of Infrared light sources and associated detectors
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Document ID:
CE0846BD
Considerations For Sampling Wet, High Pressure, And Supercritical Natural Gas
Author(s): Donald P. Mayeaux Shannon m. Bromley
Abstract/Introduction:
This paper discusses the problems encountered when sampling wet, high pressure and supercritical natural gas for on-line BTU analysis, and provides solutions and comments on how they relate to the API and GPA industry standards for natural gas sampling. It also discusses the use of phase diagrams in the design and operation of a natural gas sampling system
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Document ID:
B8F97BF8
Principles Of Multi-Dimensional Gas Chromatography
Author(s): Gregg Meidl
Abstract/Introduction:
Over the past 45 years, multi-dimensional gas chromatography has made a tremendous impact in the HPI and CPI markets. Process GCs play an important role in the areas of safety, process control, process monitoring and environmental monitoring. Modern analyzer systems have sophisticated PC based electronic controllers with LCD man-machine interface suitable for hazardous area classifications. Despite the fact that there have been considerable strides in process gas chromatographic technologies and practices, the same basic principals hold true today. This paper will cover the basic structure of a typical process gas chromatograph from the sample probe, through the sample system, GC sample valves, columns and column valves and through the detector
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Document ID:
34BCD27F
Performance Testing For Natural Gas Sample Systems
Author(s): Justin m. Harvey
Abstract/Introduction:
As we enter the second decade of the 21st century, technology is changing at an ever increasing rate. This holds true for all aspects of our lives, including communication, transportation, commerce, the internet, etc. The production, transportation and sampling of Natural Gas has also been affected positively by this surge in technology. For the purposes of this paper, the focus will be the analysis of Natural Gas. One example of a quantum leap in analysis is the method for measuring water concentrations in Natural Gas. In 30 years, the industry standard for water measurement has gone from manual chilled mirror analysis or stain tubes, to electrolytic cell-based analysis, to Tunable Diode Laser (TDL) technology. In addition, properties and characteristics of natural gas can not only be monitored digitally, but they can be monitored remotely through wireless network technology. Changes in pressures, temperature or flows in a gas pipeline can be seen and corrected via laptops
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Document ID:
B96DB4A4
Determination Of Trace Oxygen In Natural Gas
Author(s): Sam Miller
Abstract/Introduction:
The necessity for trace oxygen measurements is increasing with requirements below 100 or 10ppmv. An understanding of the considerations when choosing technology for measuring Oxygen is useful especially for remote locations or locations with high levels of corrosive contaminants such as CO2 and H2S. This paper discusses a variety of measurement methods used in natural gas such as Galvanic Cell method, the Quench Florescence method and the Gas Chromatograph method. Oxygen can be found in various types of natural gas streams. These contaminated streams include vacuum systems and traditional pipeline systems. Vacuum systems include landfills, vacuum oil recovery systems, and coal mine methane, all of which can contain percent-level oxygen whereas traditional pipelines may contain only 100 ppm of oxygen
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Document ID:
DC0A2D2D
Causes And Cures Of Regulator Instability
Author(s): Michael Hiefner
Abstract/Introduction:
This paper will address the gas pressure reducing regulator installation and the issue of erratic control of the downstream pressure. A gas pressure reducing regulators job is to manipulate flow in order to control pressure. When the downstream pressure is not properly controlled, the term unstable control is applied. Figure 1 is a list of other terms used for various forms of downstream pressure instability. This paper will not address the mathematical methods of describing the automatic control system of the pressure reducing station, but will deal with more of the components and their effect on the system stability
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Document ID:
E1EB885C
Controlling Surges In Liquid Pipelines
Author(s): Sharon Mccurdy
Abstract/Introduction:
Controlling surges in liquid hydrocarbon applications is a complex task that requires experienced engineers to dissect every section of the system. They must take into account every what if scenario and design a system that will protect piping, equipment and personnel. This paper provides a basic understanding of transient pressures, how they can occur and how they can be controlled
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Document ID:
3039CB35
Overpressure Protection Methods
Author(s): Michael Hiefner
Abstract/Introduction:
Overpressure protective devices are of vital concern to the gas industry. Safety codes and current laws require their installation each time a pressure reducing station is installed that supplies gas from any system to another system with a lower maximum allowable operating pressure. The purpose of this article is to provide a systematic review of the various methods of providing the overpressure protection. Advantages and disadvantages of each method are evaluated, and engineering guidelines are provided
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Document ID:
26DD9312
Prevention Of Freezing In Measurement And Regulatingstations
Author(s): Stephen Palmitier
Abstract/Introduction:
The competitive business environment that exists in the energy industry demands reliable service. Even though it is expensive to change energy companies, customers do have options if they become dissatisfied with their service. Significant money can be lost with trading partners through erroneous data used in establishing the value of the trade. The regulatory environment is becoming more strident in demanding safe, controlled operations. Even minor excursions outside prescribed norms can lead to substantial fines, and worse, years of having regulators going over operations with a fine tooth comb looking for any discrepancy
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Document ID:
8B9C4F6C
Selection, Sizing And Operation Of Control Valves For Gases And Liquids
Author(s): Will Sjobeck
Abstract/Introduction:
The Instrumentation, Systems, and Automation Society (ISA) defines a control valve as a power operated device that modulates the fluid flow rate in a process control system. Process plants contain hundred, if not thousands of control loops to help a certain variable reach a desired set point. These loops consist of sensors, transmitters, and process controllers that receive information and calculate necessary action to achieve a set point upon system disturbance. The control valve is one of the most common final control elements that the process controller manages to maintain the set point. A well-sized and selected control valve will be able to keep the process variable as close as possible to the set point, making the control valve a crucial part of the process. This paper will cover the importance of proper control valve selection and sizing, liquid and gas/vapor service sizing and solutions, and types of control valves
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Document ID:
2B4CAB3F
Turbulence And Its Effects In Measuring And Regulating Stations
Author(s): Terrence A. Grimley Edgar B. Bowles, Jr Adam Hawley
Abstract/Introduction:
There are many misconceptions and misunderstandings about pipe flow turbulence and its influences on flow measuring and flow regulating stations in gas and liquid transport pipelines. Many volumes have been written on the subject of flow turbulence. This paper is not intended to be a comprehensive treatment of the subject of pipe flow turbulence, but does discuss fundamental concepts and terminology, and provides information on how flow turbulence and its effects can adversely affect flow measurement and flow regulation. This information can give pipeline measurement station and regulation station designers and operators insight into ways to minimize possible adverse effects of flow turbulence
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Document ID:
58BE39EA
Flow Meter Installation Effects
Author(s): Edgar B. Bowles, Jr Adam Hawley
Abstract/Introduction:
There are many causes for natural gas flow rate measurement errors at field meter stations. Many of the sources for meter error are identified in the proceedings of this conference. For instance, errors can result from an improper installation configuration, calibration of a meter at conditions other than the actual operating conditions, or degradation of meter performance over time. Industry standards have been developed to help meter station designers and operators avoid situations that would produce gas metering errors. Typically, gas meter standards address meter design, construction, installation, operation, and maintenance. Most of the standards focus on the flow meter and the piping immediately upstream and downstream of the meter. Research has shown that many meter types, particularly inferential meters, are susceptible to errors when the flow field at the meter is distorted. The sources of flow field distortions are many. The piping geometry upstream of a flow meter can create flow distortions that may propagate several hundred pipe diameters downstream before completely dissipating. Sudden changes in the pipe diameter either upstream or downstream of a meter may also introduce flow field distortion. Branch flows, such as those produced by meter station headers, control valves, regulators, and other flow restrictions or expansions, can also create distortions in the flow
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Document ID:
3C01B094
Orifice Meter Primary Elements Standards
Author(s): Jerry Blankenship
Abstract/Introduction:
The April 2000 revision to the API 14.3 part 2 Standard includes the results of considerable test work over the past few years. Numerous changes are noted, some of which will have major effects on users of orifice measurement. The most significant impact will be in the upstream length and flow conditioner areas. This paper will discuss most of the changes and go into some detail on the more important ones. Items not mentioned essentially remain as stated in the previous issue of the Standard
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Document ID:
BD73D50E
Auditing Electronic Gas Measurement Per API Chapter 21.1
Author(s): Keith Fry
Abstract/Introduction:
Auditing evolved as a business practice as owners began to realize a standardized form of accounting must exist to prevent fraud. Financial audits made their way into businesses during the late 1700s. The industrial revolution brought about the separation of job duties beyond what a sole proprietor or family could oversee. Managers were hired to supervise the employees and the business processes. Businesses began to expand geographically where previously they were all local. Owners, who could not be in more than one place at a time or chose to be absent, found an increasing need to monitor the accuracy of the financial activities of their growing businesses. Owners responded by hiring people to check their financial results for accuracy, resulting in the process of financial auditing. In the early 1900s and at the request of the Securities and Exchange Commission, the auditors reports of duties and findings were standardized. Financial auditors developed methods of reporting on selected key business cases as an affordable alternative to examining every detailed transaction. It was found with auditing that the evaluation of both financial risk and financial opportunity was improved
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Document ID:
CC87E1D5
Auditing Gas Measurement And Accounting Systems
Author(s): Stephen T. Steve() Stark
Abstract/Introduction:
Auditing gas measurement and accounting systems has rapidly become more complex over about the last quarter century as computer-based flow meters and other modern measurement technologies have come into wider use. Before the 1980s, measurement auditing was often little more than verifying chart integration and digging through piles of field test slips looking for incorrect gas quality information, missed orifice plate changes, and errant calibration adjustments. Today, gas measurement auditing is more demanding than ever before as we depend on high-speed computer and communication networks to gather massive amounts of information required in todays fast-paced energy industry. Meter performance data, energy rates, volume rates, pressures, temperatures, flow factors, meter diagnostics, and other information is included in this enormous and ever-growing mountain of information. Much of the information collected through measurement systems is useful in ways other than simply calculating flow. Gas measurement data are also frequently used to monitor, track, and record operating conditions relating to safety, pipeline integrity, fugitive emissions, and system management
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Document ID:
E9AB0C99
Auditing Liquid Measurement
Author(s): Linda A Larson Lane Hedricks
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:
701D4E1E
Overall Measurement Accuracy
Author(s): Casey Hodges
Abstract/Introduction:
In any measurement, there is going to be inherent uncertainty associated with that measurement. Understanding the causes and effects of these uncertainties is an important tool when addressing flow measurement issues. With a solid understanding, important decisions can be made regarding many issues including meter station design, equipment evaluation, and conflict resolution. This paper will give a brief overview of factors that impact meter uncertainty, and how to understand those factors. An example of calculating the uncertainty of a metering system will be explored, along with an overview of the BLM uncertainty calculator. It should be noted that this is an introductory paper, and there are many issues with uncertainty that require more in depth knowledge and experience
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Document ID:
973F3542
API Mpms Chapter 22.2 - Testing Protocol For Differential Pressure Flow Measurement Devices
Author(s): Zaki Husain
Abstract/Introduction:
The Manuals of Petroleum Measurement Standards (MPMS) by API (American Petroleum Institute) are developed for the devices and systems installed for the measurement of oil, gas, and merchandisable petrochemical products by the oil and gas industry. Historically the API flowmeter standards are developed for devices that are accepted and installed by the industry to achieve precise and repeatable measurement for fiscal, material balance, and/or process control applications. The operating principal of field accepted installed flowmeters are based on laws of physics, where the sensors or transducers are designed to monitor the response of flow to the presence of the primary element in the flow stream or the response of the primary element or transmitted signal to the flow. Some common flowmeters that monitor response of the primary element to the flowing fluid are displacement meters, turbine meter, Coriolis meters, etc. and response of the signal to the flow are ultrasonic flowmeter, Magnetic flowmeter, thermal mass meter, etc.
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Document ID:
5C04511C
Overview Of Gpa 2172/API 14.5 Revision
Author(s): Don Sextro
Abstract/Introduction:
GPA Standard 2172-09 / API Manual of Petroleum Measurement Standards Chapter 14, Section 5, Calculating Gross Heating Value, Relative Density, Compressibility and Theoretical Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody Transfer, Third Edition, January 2009 finds wide application in the natural gas gathering and processing business as well as related natural gas handling activities because it provides methods to calculate these often-used parameters from a gas analysis. Several important changes occurred in the recent revision of this standard that became effective January 1, 2009. The main changes comprised in this revision provide methods for incorporating water vapor into the analysis calculations, include theoretical hydrocarbon liquid content (GPM) calculations on a real gas basis in this standard, discuss characterizing heavy ends in the gas analysis as well as other analysis cautions and present a number of detailed example calculations. Refer to the standard itself for requirements, procedures, details and further explanation
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Document ID:
22205C1A
Combining Intrinsic Safety With Surge Protection In The Hydrocarbon Industry
Author(s): Dan Mccreery
Abstract/Introduction:
The Hydrocarbon Measurement Industry faces a rather unique combination of problems. First, many of the areas in and around pumping, custody transfer and storage areas are classified, or hazardous, that must, according to the National Electric Code, be assessed for explosion-proofing. This may be in the form of intrinsic safety barriers or isolators, explosion-proof enclosures and conduits, purged enclosures or non-incendive components. The second challenge facing the industry is the physical exposure of most of the electronic control and measuring systems, communications, and power subsystems, each with their own sensitive, high-performance microprocessors, etc., to potentially devastating lightning and electrical surges. The goal of this discussion is to explain just how to achieve both safety and surge protection in hazardous areas using nearly identical engineering techniques
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Document ID:
836BA87E
Dot Qualification Training For Measurement And Control Technicians
Author(s): Na
Abstract/Introduction:
Effective April 27, 2001 all operators of natural gas and hazardous liquid pipelines were required to have a written Operator Qualification program in place Effective October 28, 2002 the required Operator Qualification program had to be in place and implemented -After October 28, 2002, no operator could have a person performing a covered task on their pipeline that was not qualified or, if not qualified, performing the task under the direction and supervision of a qualified person
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Document ID:
D5B9F2DA
Interface Detection In Liquid Pipelines
Author(s): James C. Lee
Abstract/Introduction:
Detecting the interface between different batches of product on pipelines has become much more important over the years, due to the increasing cost associated with downgrading the product to a product of lesser quality, or even slopping a portion as transmix. The costs associated with handling the transmix and re-refining an already refined product can be quite high. Pipeline companies have utilized many different methods of interface detection in their efforts to reduce the cost and the waste associated with the downgraded product and transmix. There continues to be advancements in technology which have become available for pipeline companies to be able to make better and more accurate cuts, which lead to greater profitability for their company. We will look at the history of interface detection and several of the technologies available today
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Document ID:
A58428F1
Multiphase Flow Measurement
Author(s): Richard Steven
Abstract/Introduction:
The measurement of unprocessed hydrocarbon flows is becoming more prevalent in the hydrocarbon production industry. Multiphase meters are now often integral in the design plans for new developments. However, the phrase multi-phase flow covers a huge range of flow conditions and metering these varied flows has proven a major challenge to engineers. Furthermore, due to the relatively recent arrival of these technologies on the market, and, the relatively complex and proprietary nature of the products leading to the finer details of operation not being divulged, there is often a lack of technical understanding amongst the multiphase meter users. In this paper, definitions of the phrases multiphase flow and wet gas flow will be discussed. There will be a discussion on the requirement for multiphase metering before multiphase flow patterns and the methods of predicting them are discussed. Finally, an overview of the common multiphase meter generic principles will be given
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Document ID:
E020B35B
Odorization Of Natural Gas
Author(s): Kenneth S. Parrott
Abstract/Introduction:
the demand for natural gas has grown at an astounding rate. There is virtually no area of North America that doesnt have natural gas provided as an energy source. The methods of producing, transporting, measuring, and delivering this valuable resource have advanced, and improved in direct relation to the demand for a clean burning and efficient fuel. While todays economic climate determines the rate of growth the gas industry enjoys, in a broad sense, natural gas is certainly considered essential and a fuel of the future. Of primary importance, in the process of delivering gas for both industrial and public use, is providing for the safety of those who use it. Whether in the home, or workplace, the safety of all who use or live around natural gas systems is of primary concern. Natural gas is a combustible hydrocarbon and its presence may under certain conditions be difficult to determine. One need only to remember the tragic explosion of the school building in New London, Texas in the 1930s to understand the potential for injury when natural gas accidentally ignites. Because of this possibility for accidents, regulations have required the odorization of natural gas when it comes in contact with the population. This enables people living and working around natural gas to detect leaks in concentrations well below the combustible level of the natural gas
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Document ID:
F480AF22
Orifice Meter Tube Dimensional Tolerances
Author(s): Michelle Beckner
Abstract/Introduction:
The orifice meter is one of the older devices that is utilized in the measurement and regulation of fluid flow. Romans regulated water flows to their homes by the use of orifice. Benoulli, Torricelli, and Venturi, discovered the original concept that the pressure of a flowing fluid varies as its velocity changes. When a flowing fluid is made to speed up by restricting the cross-sectional area of the flow stream, a portion of the pressure energy is converted into velocity energy and the pressure drops. Using this relationship with the fact that the quantity of the fluid flowing is equal to the product of the velocity times the cross-sectional area of the flow stream we can have flow measurement in the orifice meter. In order to correlate the theoretical flow with actual flow concepts there became a need for basic dischargecoefficient research to actually utilize these theories in custody transfer of products. In the early part of the last century the American Gas Association (AGA) established the Gas Measurement Committee to do just such
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Document ID:
58A76F06
Program For Training A Gas Measurement Technician
Author(s): Jimmy Galyean
Abstract/Introduction:
Although the concept of having a program for training a Gas Measurement Technician is not new, the ever changing contour of the natural gas industry creates challenges for the companies involved, but even more so for the technicians who takes care of the measurement equipment out in the field. Technicians today must be able to retain technical expertise in order to support antiquated equipment while continuously expanding the knowledge required to install, operate and maintain advanced technologies. Since electronic equipment has became more sophisticated, in addition to being the equipment of choice, remaining proficient is an ongoing challenge. Technicians today not only have to install, operate and maintain measurement equipment but may also be responsible for other equipment such as regulation and control, odorization, gas quality, communications and in some cases facility maintenance. Even with these added responsibilities the expectations of having quality measurement, regardless of the equipment being used remains the same. Providing technicians the necessary training they need is extremely imperative
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Document ID:
0A948B73
The Effects Of Additives On Metering In Liquid Pipelines
Author(s): Joseph T. Rasmussen
Abstract/Introduction:
Todays refined fuels are formulated using a recipe of chemical blending and complex processing. Current blends that make-up fuel & chemicals introduce new problems that challenge product quality and performance. Refined products can be altered or degrade prior use by secondary forces such as environment and handling. A wide range of performance and handling problems are minimized or resolved by use of chemical additives. Additives to fuel products are often included in the refining processes that address these problems. Fuels may require additional blending of additives separate from the refining process. The effect these additives have on liquid metering is variable based on their composition and concentration
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Document ID:
95E982B9
Blms Role In Oil And Gas Measurement
Author(s): Richard Estabrook
Abstract/Introduction:
BLM manages about 700 million acres of Federal and Indian mineral estate, which contributes a significant portion of domestic oil and gas production. BLMs role in oil and gas measurement is to ensure that volumes and qualities are accurately measured and properly reported, as Federal and Indian royalty is derived from these measurements. BLMs measurement requirements are dictated by Federal laws, from which BLM develops regulations, Onshore Orders, and Notices to Lessees. Most oil and gas measurement functions are carried out at the Field Office level through the approval of permits and variance requests. BLM inspects Federal and Indian measurement facilities to ensure compliance with regulations, Onshore Orders, and Notices to Lessees, as well as permit Conditions of Approval. BLM inspectors have various enforcement tools to ensure compliance. The public has the opportunity to comment on all proposed rulemaking, and parties adversely affected by specific decisions have several avenues of appeal
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Document ID:
09559CFE
Meter Selection
Author(s): Robert Fritz
Abstract/Introduction:
This paper is intended to provide general guidelines & criteria for the evaluation & selection of a high pressure gas meter, including a discussion of the basic operating principles and installation and maintenance considerations. This paper will concentrate primarily on three high pressure/high volume custody transfer flow meters, Orifice, Ultrasonic and Turbine. A short discussion will be provided for other alternative types of flow meters and different gas stream conditions. When selecting a gas flow meter for particular application remember that there is no one Panacea for flow measurement. No one meter is the right choice for all applications. The following general criteria need to be considered in evaluating which type of meter to select
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Document ID:
E65F39D4
Cone Meters For Liquid And Gas Measurement
Author(s): Kenneth Reed, III
Abstract/Introduction:
Cone Meters differ from other differential pressure type meters, such as Orifice Meters and Venturi Meters, basically by design only. They are all required to meet API Chapter 22.2 test criteria developed and published in 2005 and still being updated today. The Cone Meter is designed to measure liquid or gas. Cone Meters are proprietary in design and have limited third party testing due to patented designs and length of use in the Industry. The Orifice Meter is the oldest meter of the three that we will discuss and has the most third party flow lab test data available. The Venturi Meter history has mostly been utilized for liquids and steam. The Venturi is also known to preform very well in harsh flows, such as sewage, waste water and pulp due to its free flowing design. In recent years Venturis are more commonly being used for LNG & CNG due to the ability to construct them from a wide variety of materials
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Document ID:
D972CE60
Measurement Scene Investigations
Author(s): Ray Glidewell
Abstract/Introduction:
Losses in hydrocarbon measurement can be a significant cost to a companys profits. Consequently the gain/loss for system balances gets a lot of attention and scrutiny. In the business of hydrocarbon measurement, we strive to prevent significant gain/loss percentages. Sometimes, however, despite our best efforts, discrepancies will occur and they will have to be investigated. Before you can find a measurement discrepancy, first you need to know what to look for. What does a measurement discrepancy look like? How will you know one when you see it? Discrepancies will reveal themselves in a system balance as either a gain or a loss. Even better than finding a discrepancy, is preventing a discrepancy. Prevention is accomplished by developing and implementing proactive surveillance activities. Monitoring selected data points regularly and often can prevent discrepancies from occurring in the first place. However, significant discrepancies can and do occur even after you have done everything you can to prevent them. Thats when youll have to complete a measurement scene investigation in order to pinpoint what caused the discrepancies so you can eliminate the cause and prevent the discrepancy from reoccurring again and again.
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Document ID:
4D172CF4
Measurement Policies And Procedures - Development And Implementation Considerations
Author(s): Bruce Wallace
Abstract/Introduction:
With proper consideration and with buy-in from stakeholders, well designed and documented measurement practices help reduce company costs. Cost reductions include those associated with Lost-and-Unaccounted-for (L&U), asset maintenance, and labor. Furthermore, good measurement procedures help employees perform safely and effectively and help support stable, predictable measurement processes. In this paper, we will discuss: What happens when measurement practices are not effective? What are the metrics to determine if measurement practices need improvement? Why do policies and procedures fail? When should policies and procedures be reviewed and updated? Who is responsible for creating and maintaining policies and procedures? How do policies and procedures get effectively communicated
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Document ID:
CE8F075E
Benefits Around Timely Analysis Of Measurement Data
Author(s): Keith Fry
Abstract/Introduction:
Verifying measurement data can be challenging. Challenges include processing an overwhelming amount of data, choosing meaningful data types and validation criteria, and validating the data in a timely manner. Failure to meet these challenges can lead to undesired outcomes such as inaccurate measurement results, prior period adjustments in accounting, and increased costs. To efficiently and accurately validate measurement data for the monthly cycle, a number of things must be evaluated and implemented. Considering these topics in advance will help resolve anomalies and outstanding issues
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Document ID:
0799BF00
Measurement Management System
Author(s): Christopher Levy
Abstract/Introduction:
Hydrocarbons have long been a main energy source transportation from supply to demand is among the most critical factors in sustaining our way of life. hydrocarbons are measured for environmental protection and/or accounting systems. is a dynamic, unique field with unique challenges. undergo continuous change as technology continues to evolve at an increasingly rapid pace. New technology requires new skills and companies are faced with the task of devel these necessary advanced work force competencies. Because a decrease in work force knowledge and skills coupled with an increase in infrastructure complexity can lead to a perfect storm of inefficiency and po measurement performance, a process control and improve a companys measurement performance.
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Document ID:
7B0A3323
Contributors To Historical Advances In Natural Gas Measurement
Author(s): Jeremiah Gage
Abstract/Introduction:
When discussing a historic subject, controversy often arises. Like any historical subject the vastness of contributors and information is immeasurable. The author for this paper picked the people based on his research and his interest in the given subject of natural gas. This is not a technical paper it is a historical paper and is written in a historical prose
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Document ID:
38431BD4
Applications And Fundamentals Of Catalytic Heaters In Measurement Applications
Author(s): Chad Richards
Abstract/Introduction:
Catalytic heaters are used to prevent liquid distillation and freezing in natural gas which is a common problem in regulation and measurement as often caused by the Joules - Thompson Effect. Since the maximum operating temperature is always well below the temperature for ignition required of natural gas, the heaters are ideally suited in hazardous locations in the oil and gas industry. As relevant to measurement applications, this paper will cover the principals of catalytic heater installation and operation
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Document ID:
C1231508
Cyber Security Board Room To The Control Room
Author(s): Daniel R Crandell
Abstract/Introduction:
Many of todays Industrial Control Systems (ICS) are becoming more advanced and complicated than ever before. No longer can we say that todays Industrial Control Systems (ICS) are truly isolated. With the advancement in technologies and the introduction of Ethernet and Transmission Control Protocols (TCP), Meters, Pressure and Density Transmitters, Flow Computers, Programmable Logical Controllers (PLC), Distributed Control Systems (DCS) are just a few ICS devices that are becoming more vulnerable to cyber attacks. The data derived from these systems is proving itself to be invaluable to company board members in their decision making to advance their company profits and gain a foot hold in an increasingly competitive market place. The increase of data acquisition systems like Historian Servers accessing the information highway via WAN connections increases the risks to the control network. Cyber security attacks are becoming more prevalent in the industry of automation as a whole. This paper will present the reader with tools and methodologies to mitigate cyber attacks and lay the foundation for an in depth approach to defense techniques to enhance the security posture of their company.
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Document ID:
20670B35
About Ishm 2012
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:
143B103A