Measurement Library

International School of Hydrocarbon Measurement Publications (2011)

Download collection of documents about ISHM 2011 including table of contents, event organizers, award winners, committee members, etc.


International School of Hydrocarbon Measurement

Basics Of High Pressure Measuring And Regulating Station Design
Author(s): Thomas G. Quine
Abstract/Introduction:
This presentation is intended to illustrate the recommended steps for implementation of successful projects from preliminary engineering to project data books and commissioning. In addition, the key components and ideal P&ID are reviewed in detail to define the technical components of M&R facilities. These principles can be applied to measurement and control projects, LNG projects, and LPG projects. When considering current design practices for M&R facilities, it is useful to view the current drivers in the industry, which can then be viewed on an annual basis. For example, a resurgence of gas fired generation is predicted along with a continued emphasis on bi-direction facilities between major pipes. The strategy presented involves the following disciplines: performing through preliminary engineering, performing final design, procurement, the qualification of installers, construction, testing, commissioning, training and documentation.
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Document ID: E1273ECC

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: 0163D3A4

Coping With Changing Flow Requirements At Existing Meter Stations
Author(s): Barry Lagadinos
Abstract/Introduction:
In the natural gas distribution business, the measuring station is the cash register for buying and selling natural gas. When measuring stations are installed, they should be designed to meet a percentage of the maximum load with a growth factor included in the design of the station for future growth. A perfect measuring station will measure all the gas needs correctly and be the smallest size possible. When sizing a measuring station, it is often assumed that not all equipment it serves will be operating at full capacity 100% of the time. An example of sizing would be a measuring station sized to measure the gas at 70% of the maximum load. When a measuring station is sized, it also needs to be able to measure low flow rates accurately. Accurate metering of both high and low flow rates may not be possible with a single meter application. Flow rates can change permanently or temporarily. Some of these changes in flow rates and methods to deal with them will be covered.
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Document ID: E5F95331

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: 129DB3B1

Determination Of Leakage And Unaccounted For Gas
Author(s): David Wofford
Abstract/Introduction:
Leakage and unaccounted for gas volumes are of the most significant costs of operation for natural gas producers, gatherers, processors, transporters and distribution system operators. These operational costs are so significant that such are directly addressed in tariffs, rate case filings and contractual agreements between parties in order that such may be itemized as a cost of operation, equitably managed and responsibly mitigated. Common acronyms denoting lost and unaccounted for gas volumes are LAUF (Lost And Unaccounted For), LUG (Lost and Unaccounted for Gas) and UAF (UnAccounted For). All of these designations refer to the same issue - Product that you believe you should be able to account for but for some reason cannot. For the sake of this discussion, LAUF shall be our acronym of reference
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Document ID: A4B8AB73

Effects And Control Of Pulsation In Gas Measurement
Author(s): Ray G. Durke Edgar B. Bowles, Jr
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: BC20246A

Effects Of Abnormal Conditions On Accuracy Of Orifice Measurement
Author(s): Thomas B. Morrow
Abstract/Introduction:
In 1971 E. J. Burgin of Florida Gas Transmission Company presented a paper at ISHM entitled Factors Affecting Accuracy of Orifice Measurement (Primary Element). Burgin noted that AGA Report No. 3 (of that time) claimed that an orifice meter with flange taps and with a diameter ratio, ?, between 0.15 and 0.7, fabricated and operated in accordance with the specifications in the standard, would have a discharge coefficient value within ? 0.5% of the value calculated from the orifice equation. The purpose of Burgins paper was to examine some of the specifications in the orifice meter standard and to review the effect upon measurement accuracy when the specifications are ignored
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Document ID: FB2D0B86

Fundamentals Of Gas Measurement I
Author(s): Douglas E. Dodds
Abstract/Introduction:
To truly understand gas measurement, a person must understand gas measurement fundamentals. This includes the units of measurement, the behavior of the gas molecule, the property of gases, the gas laws, and the methods and means of measuring gas. Since the quality of gas is often the responsibility of the gas measurement technician, it is important that they have an understanding of natural gas chemistry
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Document ID: C3BE0D1C

Fundamentals Of Gas Measurement II
Author(s): Jerry Paul Smith
Abstract/Introduction:
A knowledge of the Fundamentals of Gas Measurement is essential for all technicians and engineers that are called upon to perform gas volume calculations. These same people should have at least a working knowledge of the fundamentals to perform their everyday jobs including equipment calibrations, specific gravity tests, collecting gas samples, etc. To understand the fundamentals, one must be familiar with the definitions of the terms that are used in day-to-day gas measurement operations. They also must know how to convert some values from one quantity as measured to another quantity that is called for in the various custody transfer agreements
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Document ID: CD7C9D86

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: 454273D8

Fundamentals Of Gas Turbine Meters
Author(s): Richard C. Deangelo
Abstract/Introduction:
The majority of all gas measurement used in the world today is performed by two basic types of meters, positive displacement and inferential. Positive displacement meters, consisting mainly of diaphragm and rotary style devices, generally account for lower volume measurement. Orifice, ultrasonic and turbine meters are the three main inferential class meters used for large volume measurement today. Turbines are typically considered to be a repeatable device used for accurate measurement over large and varying pressures and flow rates. They are found in a wide array of elevated pressure applications ranging from atmospheric conditions to 1440 psig. Turbine meters have also become established as master or reference meters used in secondary calibration systems such as transfer provers. A significant number of both mechanical and electrical outputs and configurations have become available over the past 50 years of production
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Document ID: 6AA39E65

Fundamentals Of Orifice Meter Chart Recorders
Author(s): David Cofer
Abstract/Introduction:
There are two basic components that need to be discussed to understand the fundamentals of orifice meter measurement. One is the Primary Element, which consists of the orifice fitting, orifice plate, meter tube, and other associated components. The other is the Secondary Element, which consists of the equipment used to measure and record the values needed to calculate a volume of gas passing through the Primary Element
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Document ID: D4D4EC72

Installation And Operation Errors In Gas Measurement
Author(s): Dr. Thomas B. Morrow Edgar B. Bowles, Jr.
Abstract/Introduction:
Installation errors may occur when an instrument is used in a manner different from how it was calibrated. For example, suppose that a temperature sensor is calibrated in a stirred, constant temperature bath. During calibration, the sensor is in thermal equilibrium with the circulating fluid, and the fluid and sensor temperatures are the same. Next, let the same sensor be used to measure the temperature of natural gas flowing through a pipe at low velocity. If the pipe wall temperature is different from the flowing gas temperature, convection heat transfer will occur between the gas and the pipe wall, radiation heat transfer will occur between the pipe wall and the sensor, and convection heat transfer will occur between the sensor and the flowing gas. In this example, the sensor would not in thermal equilibrium with the flowing gas and the sensor temperature would be different from the flowing gas temperature
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Document ID: 18E8BC1E

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: F5027A30

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
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Document ID: 4E6486A5

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: 5454B6E9

Multipath Ultrasonic Flow Meters For Gas Measurement
Author(s): Eric Thompson
Abstract/Introduction:
The use of ultrasonic meters for custody (fiscal) applications has grown substantially over the past several years. This is due in part to the release of AGA Report No. 9, Measurement of Gas by Multipath Ultrasonic Meters Ref 1, Measurement Canadas PS-G-E-06 Provisional Ultrasonic Specification Ref 2, and the confidence users have gained in the performance and reliability of ultrasonic meters as primary measurement devices. Just like any metering technology, there are design and operational considerations that need to be addressed in order to achieve optimum performance. The best technology will not provide the expected results if it is not installed correctly, or maintained properly. This paper addresses several issues that the engineer should consider when designing ultrasonic meter installations
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Document ID: 32894464

Fundamentals Of Orifice Metering
Author(s): Bob Carlson Patrick Speranza
Abstract/Introduction:
Throughout the oil and gas industry, the need exists for accurate and economical measurement of process fluids and natural gas. Orifice Meters, sometimes referred to as Orifice Fittings or head loss flow meter, satisfy most flow measurement applications and are the most common flow meter type in use today. The Orifice Meter is chosen most frequently because of its long history of use in many applications, versatility, and low cost, as compared to other available flow meter types
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Document ID: 6CE0ECCA

Orifice Meter Maintenance And Operation
Author(s): Scott Smith
Abstract/Introduction:
The natural gas industry has seen many changes lately. The world population is increasing and with this the energy demands in the world are also increasing. Producers and pipeline companies have seen tremendous growth and reorganization through these increased demands for energy. The advances in technology in the last decade have put a computer and cellular phone at everyones fingertips literally and increased the need for electricity, thus the need for natural gas to generate this electricity. With this increased demand for natural gas, the logistics involved in acquiring it, and the profit differential between these two, the need for proper maintenance is more important than ever.
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Document ID: F1ED2356

Thermometry In Gas Measurement
Author(s): Stephen T. Steve() Stark
Abstract/Introduction:
Measured several times between the wellhead and its final point of consumption, natural gas temperature is dynamic it changes frequently and constantly. Gas molecules heat up when packed tightly together, such as when they undergo compression. As gas expands after flowing through a regulator or other restriction, it cools down. Natural gas temperature is also affected by the temperature of the pipe through which it flows. The measurement of gas temperature contributes directly to measurement accuracy. The greater the temperature measurement error, the higher the overall measurement uncertainty becomes. Even relatively small temperature measurement errors can have a large impact on the bottom line.
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Document ID: 49C800CF

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: 4BBD5DE9

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
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Document ID: EC6C9997

Contaminant Accumulation Effects On Gas Ultrasonic Flow Meters
Author(s): Charles W. Derr Tina m. Newsome
Abstract/Introduction:
One of the most significant discussions in the gas ultrasonic flow meter industry centers around the effect of accumulation of contaminants on the accuracy of flow measurement and the performance of the gas ultrasonic flow meter (GUSM). The effects of contamination on a gas ultrasonic metering systems are believed to be less than that of other measurement devices. The increasing usage of ultrasonic metering warrants a more in-depth study of these effects and the symptoms and measurement errors that may result. There are three important factors to consider when evaluating contaminant effects. They are ultrasonic meter performance inclusive of the flow dynamics through them, total system operation and measurement financial impact. Factors such as these have a direct correlation to the operating expenses which are monitored closely by virtually all gas companies. High volume throughput of expensive gas means that small errors when ignored are potentially large sums of money that may be Lost. This discussion will help describe how that accuracy and operation of the gas ultrasonic meter are affected by the build up of contaminants. A real captured example is shown in Figure 1. below
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Document ID: 84E6BFD7

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
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Document ID: 5431D3CC

Measurement And Regulation Operations Of A Ldc
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: 59B4246B

Flare Measurement Advanced Ultrasonics
Author(s): 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. With new government legislation, producers, refineries and chemical companies have been looking for a cost effective solution to reduce emissions and to provide tighter control for both leak detection and mass balance. To tolerate the extreme process conditions often found in a flare line, yet provide accurate measurement to comply with international regulators such as the Energy Resources Conservation Board in Canada, the European Union, or the Texas Commission of Environment Quality, the technology of choice is important. Several metering technologies have been tested with little success. To understand why the results have been dismal, one needs to fully understand the challenges associated with the application. Further investigation towards the effects of sonic noise generated from high gas velocities, elbows, Ts, and pipe segments, has been conducted and the results detailed in this paper
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Document ID: 316612CB

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
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Document ID: C9EFA8AB

Application Of Densitometers To Liquid Measurement
Author(s): Mike Pritchard
Abstract/Introduction:
This paper looks at the common methods of process density determination, discusses density units and derived units, limits of accuracy and validation methods plus installation effects and some of the more common applications in the oil and gas business
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Document ID: E8022C2E

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: 8FAA8F71

Automated Truck Loading Systems
Author(s): Jason Donnell
Abstract/Introduction:
Bulk storage facilies, often refered to as distribution terminals, must load and unload liquid product between storage tanks, railcars, tank trucks, and barges. The transfer of petroleum products has become a concern in areas such as safety, security, measurement accuracy, and regulatory requirements. Due to the advancement of electronic systems, improvements have been made in these areas. This report will focus on useful preset features and the types of blending that are available using an electronic preset. Blending configurations that will be covered include the sequential blender, the ratio blender, the side stream blender, and the hybrid blender
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Document ID: 2649609B

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: 969660F7

Crude Oil Blending
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
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Document ID: FDFFFE19

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: 9A98A343

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: 9ADF0559

Displacement Meters For Liquid Measurement
Author(s): Tom Piskorski
Abstract/Introduction:
The petroleum measurement industry continues to demand a liquid flow meter that has a high degree of repeatability, linearity, and stability. Meter repeatability is the ability of the meter to reproduce the same meter factor, given the same conditions. Linearity is the ability of the meter to have a meter factor within a specified percentage deviation from maximum flow in comparison to minimum flow. Stability is the meters ability to reproduce the same meter factor time after time for some given length of time, given that the operating conditions are the same
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Document ID: 66038F8D

Effects Of Flow Conditioning For Liquid Measurement
Author(s): Blaine Sawchuk
Abstract/Introduction:
A 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
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Document ID: 74B55F2F

Basic Applications Of Telemetering Systems
Author(s): Tommy Mitchell
Abstract/Introduction:
In a fast changing natural gas industry today it is important for companies to utilize all available technologies in order to safely operate and maintain a competitive edge in todays market place. One of many available technologies is telemetering. To understand telemetering let us first give a good definition of telemetering and how it applies to todays natural gas industry. Telemetering is defined as: The science of sensing and measuring information at a remote location and transmitting that data to a convenient location to be read and recorded. From this definition we can see that telemetering, as it applies to the natural gas industry, is simply a way to gather, read and record data remotely so it can be utilized. Some of the most common reasons companies install a basic telemetering system today are safety, increase production, improve operations efficiency, and monitor pipelines. However with todays advanced Flow Computers and RTU designs the reasons listed above can be easily achieved in most cases by installing one unit per location. It is the intent of this paper to cover basic telemetering principles as they apply to areas of the Oil and Gas Industry
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Document ID: 4A698A5B

Effects Of Fluid Properties On Pipeline Measurement
Author(s): Jim Smith
Abstract/Introduction:
Measurement of liquid hydrocarbons in most pipelines today is done on a standard volume basis or by mass. These 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: 36796C33

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
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Document ID: E9BB269C

Evaporation Loss Measurement For Storage Tanks
Author(s): Warren A. Parr, Jr
Abstract/Introduction:
In the 1950s hydrocarbon evaporation loss from storage tanks was studied to develop emission estimating equations. At that time, the primary driver for knowing the evaporation rate was system loss control. During the early 1990s, the US Environmental Protection Agency (EPA) began programs for stricter record keeping and reduction of storage tank emission. This forced industry to scrutinize the accuracy of existing evaporation loss estimating equations and to develop improvements to various tank appurtenances in an effort to lower hydrocarbons emissions. Much of the EPA activity was focused on floating roof tanks. This paper will review:
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Document ID: 4A400E2B

Basic Electronics For Field Measurement
Author(s): Dale Gary David Nichols
Abstract/Introduction:
This paper is written with the idea of presenting basic electronic principles and how to apply these to common applications in the oil and gas industry
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Document ID: 919FA635

Scada Systems
Author(s): Ian Metcalfe
Abstract/Introduction:
The definition of SCADA is Supervisory Control and Data Acquisition. The major function of SCADA is for acquiring data from remote devices such as valves, pumps, transmitters etc. and providing an overall control remotely from a SCADA Host software platform. This provides process control locally so that these devices turn on and off at the right time, supporting your control strategy and a remote method of capturing data and event (alarms) for monitoring these processes. SCADA Host platforms also provide functions for graphical displays, alarming, trending and historical storage of data. Historically, SCADA products have been produced that are generic with a one shoe fits all approach to various markets. As SCADA has matured to provide specific solutions to specific SCADA markets it has provided solutions for wide area network SCADA systems that rely on tenuous communication links. These types of SCADA systems are used extensively throughout the Oil & Gas market due to the fact that assets are spread over large geographical areas.
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Document ID: 90503058

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: 416EEA66

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: 824E8AF4

Economics Of Electronic Gas Measurement
Author(s): David Kimbrough
Abstract/Introduction:
Reasons to upgrade chart recorders to Electronic Flow Measurement (EFM) is a discussion that has been ongoing for years. In the early years EFMs were limited in their capabilities and the cost was high so companies were slow in accepting them. Being able to see measurement and pipeline pressures remotely was needed but the technology wasnt there yet. Today the EFMs can provide a vast array of information, accurately and timely at a reduced cost. Many companies have already switched to EFMs but there are several companies that havent made the jump yet especially producers. There are several factors to consider when making the decision to switch from chart recorders to EFMs. This discussion will explain the benefits of having remote access to meters and production equipment. There is a cost to removing chart recorders and installing EFMs with communications but the benefits can easily outweigh the expense. Listed below are the areas that will be discussed concerning these benefits
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Document ID: C1259A1A

Fundamentals Of Liquid Measurement II
Author(s): Doug Arrick
Abstract/Introduction:
Measurements of liquid petroleum can be performed with the liquid in a static or dynamic state. Custody measurements are made in both states. Static measurements of petroleum liquids are made with the liquid in a tank. This paper will discuss the steps required to calibrate, gauge and sample tanks. These are the steps necessary to measure liquid petroleum in a static state
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Document ID: 3659DF9A

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: 333A8F37

Production Equipment Effect On Gas Measurement
Author(s): Dean Weber
Abstract/Introduction:
Production and process equipment, due to the mechanical and gravitational process of the equipment, can have a great effect on the quality of the gas or liquid being measured. Improper measurement equipment based on conditions is also a concern. We will discuss some of the concerns with the physical operation of the equipment as well as choice of measurement equipment
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Document ID: CAA9B023

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: D97B823D

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: C6611779

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: 4A0ADCBB

Helical Turbine Meters For Liquid Measurement
Author(s): Herb Decker
Abstract/Introduction:
The helical turbine meter has been around for 85 years and has seen numerous improvements over this period. The swept wing rotor design has been introduced along with anti-fouling bearings and service in lines where DRA is present. Normally a helical turbine meter is used in either multi-viscosity crude or finished product pipelines where the meter is expected to provide a single meter factor over a wide range of products and viscosities. In recent times the helical has provided excellent performance in crude applications as high as 1,400 cSt. We will also cover application of the meter in custody transfer measurement to take advantage of its unique capabilities
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Document ID: 875E8156

Installation And Operation Of Densitometers
Author(s): John V. Bailey
Abstract/Introduction:
densitometer is a dynamic device used to measure the density of a flowing stream. A densitometer is used to measure the density of liquid hydrocarbons and finished products like propane, gasoline and liquid mixtures such as, Y-grade natural gas liquids (NGL). This article addresses on-line liquid density measurement. There are several applications in the oil and gas industry where measured density is an important and foremost component of total liquid measurement. The major use of densitometers is to determine the mass-volume that has passed through the flow meter. This quantity may be determined either through mass or volumetric measurement techniques. A secondary use of a densitometer is to detect a pipeline product interface. One of these is the plug of liquid between two dissimilar products shipped in the same pipeline. Continuous density measurement provides a pipeline operator with the ability to monitor the density change from one batch to the next.
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Document ID: F604645D

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: FCB9419A

On-Line Computers For Custody Transfer
Author(s): Peter P. Jakubenas
Abstract/Introduction:
Until the use and acceptance of the turbine meter and pipe provers in the 1960s, very few electronic devices were used for the measurement of oil or gas. The turning shaft of positive displacement meters powered a number of accessories including counters, printers, mechanical temperature and gravity compensators and meter factor calibrators. The ATG is a wheel and disc mechanical integrator that is still commonly used in gathering system pipeline locations for automatic temperature and gravity compensation of meter totals where electric power may not be available. Gas measurement was accomplished using mechanical circular chart recorders. Total amount of flow was determined by integrating the area under the graph of differential pressure using a planimeter
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Document ID: A4A0D0F2

Liquid Measurement Field Surveys
Author(s): Miles Chaney
Abstract/Introduction:
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: FD0C608C

Real-Time Electronic Gas Measurement
Author(s): King Poon
Abstract/Introduction:
With natural gas production in the United States being more than 60 billion cubic feet (BCF) per day, accurate gas measurement is paramount and the delivery of this measurement data must be on time (i.e. accurate real-time data). Production, engineering, gas nomination, billing and various administrative functions are just a few of the departments now requiring real-time information to process the massive amount of data. Instead of charts, electronic flow computers are now used by the natural gas industry to automate the data collection and control process. Host computer systems periodically collect data from the flow computers and send control commands, gas analysis data and configuration information to the flow computers as part of daily operations. The success of real-time measurement requires the coordination of many functions, including measurement and control, communications, data collection, archiving, post processing, reporting, and the sharing of this information. Breakdowns, in any of these functions, affect the integrity of the entire system and prevent the data from being distributed to the end users in a cost efficient manner.
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Document ID: F61E24FB

Liquid Measurement Station Design
Author(s): Al Odowd
Abstract/Introduction:
The industry continues to benefit from advancements in metering technologies, instrumentation and computer control systems applied to liquid measurement equipment. These advancements result in increasingly complex and sophisticated requirements for interfacing with the mechanical equipment. Complete compatibility of the instrumentation system with the metering components must be incorporated in the design to assure optimum functionality of the system. This paper outlines design considerations and other factors that should be considered in specification and construction of flow measurement stations for hydrocarbon liquids
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Document ID: A68C696F

Spread Spectrum Systems For Efm And Scada
Author(s): Jim Gardner
Abstract/Introduction:
As oil and gas companies work toward greater automation and e-business solutions, the challenges of getting real-time, reliable data from remote locations continues to be one of the greatest hurdles. Today, there are many fine choices in electronic flow measurement (EFM) and remote terminal unit (RTU) equipment available. There also are many fine bug free software programs to archive, audit, and display the collected data. The single biggest problem remains communications. It is a commonly held belief that over 80 percent of all SCADA system problems are communication failures. To further complicate the problem, the FCC-licensed radios systems that have been the backbone of the SCADA and telemetry business for many years are becoming hard to come by. In many areas, there are no more licenses to be had. Because of the saturation of existing licenses, the FCC has re-farmed licenses to create smaller broadcast areas, less bandwidth and smaller frequency variations allowances
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Document ID: 47C9F6FA

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 80 to 100 million dollars. 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: 26E6351A

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: FBFDE7DF

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: 76824408

Mass Meters For Liquid Measurement
Author(s): Michael Keilty
Abstract/Introduction:
A mass flowmeter is a system that provides a measurement of fluid flow in units of mass pounds, tons. Mass flowmeters could either measure the mass flow directly or derive the mass flow from a volumetric flow measure using the known density of the liquid. The Coriolis flowmeter is a type of flowmeter which measures the mass of the liquid flow directly. Coriolis mass flowmeters were first introduced more than 30 years ago. Global acceptance has spread across all industries where precision flow measurement is needed. Today, installations number in the hundreds of thousands of measurement points including those in liquid hydrocarbon and natural gas applications. This paper will review the Coriolis mass flowmeter technology describing the differences and similarities between Coriolis flowmeters and electronic and mechanical meters and looking at some latest developments in Coriolis mass meter design and operation
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Document ID: 3AED6398

Testing, Maintenance, And Operation Of Electronic Flow Computers For The Gas Industry
Author(s): Stephen T. Steve() Stark
Abstract/Introduction:
Natural gas flow computers came into much wider use for custody transfer (fiscal) measurement beginning in the late 1980s following their less common application in the 1970s and before. Used almost exclusively to calculate flow, early flow computers simply replaced chart recorders and offered an alternative means of storing data. With improvements in microprocessors, field-hardened electronics, power systems, communications, batteries, and pressure transducers came countless other uses. No longer as they used to simply calculate flow. Today in 2011, flow computers provide large amounts of data and perform tasks that are essential to the success of a complex and fast-paced gas energy industry. We will focus here only on gas quantification matters relevant to testing, maintenance, and operation of natural gas flow computers, and steps taken to help ensure the reliable calculation of natural gas quantities.
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Document ID: FF375EF8

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
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Document ID: EBC3D609

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: 6DA4D72A

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
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Document ID: ABF23932

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
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Document ID: CE77E8CB

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: 58B9FCA7

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: 1CBC3691

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: 38815C34

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: CC9F7EF4

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: D947BCE2

Design, Calibration, And Operation Of Volume Standards
Author(s): Sherry Sheckels
Abstract/Introduction:
Test measures are designed to deliver a known liquid volume when drained. Their primary use is to calibrate displacement and tank provers in the field by the waterdraw method.1, 2 Accurate test measure volume calibrations are critical to achieving low uncertainty calibrations with flow provers in the field. Test measures can either be invertible or bottom-drain type. Invertible test measures are usually less than 40 L (10 gal) while bottom-drain test measures are larger than 40 L (10 gal). Each year, approximately 100 test measures used for field calibrations are calibrated at the National Institute of Standards and Technology (NIST) to comply with API standards.3 NIST uses several calibration methods depending on the size of the test measure: 1) the gravimetric method, 2) the gravimetric transfer method, and 3) the volumetric method.4 NIST calibrations include a neck scale calibration at five levels spaced over the range of the neck scale. To ensure accurate customer calibrations and to maintain an ISO 17025 compliant quality system5 NIST regularly performs calibrations of the 60 kg and 600 kg balances used during the calibration and calibrates volume check standards
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Document ID: CD162C64

Pycnometer Installation, Operation And Calibration
Author(s): Robert L. Bob() Armbruster
Abstract/Introduction:
This paper describes pycnometers that are used to calibrate density meters (densitometers). Within this paper, the fluid stream is to be considered a Natural Gas Liquid, Refined Product or Supercritical Fluid. Important points for consideration are: ? Pycnometer Selection ? Pycnometer Certification, Field Validation and Recertification ? Proper Pycnometer Installation ? Densitometer Calibration
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Document ID: BB138881

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: CF84334C

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: 11C1FC15

Flow Calibrating Ultrasonic Gas Meters
Author(s): Joel Clancy
Abstract/Introduction:
The primary method for custody transfer measurement has traditionally been orifice metering. While this method has been a good form of measurement, technology has driven the demand for a new, more effective form of fiscal measurement. Ultrasonic flowmeters have gained popularity in recent years and have become the standard for large volume custody transfer applications for a variety of reasons. Most users require flow calibrations to improve meter performance and overall measurement uncertainty. The latest revision of AGA Report No. 9, Measurement of Gas by Multipath Ultrasonic Meters, Second Addition Ref 1, now requires flow calibration for ultrasonic flow meters when being used for custody transfer applications. What considerations then, should be taken when choosing to flow calibrate an ultrasonic flowmeter? What are the benefits to the user? What should a user expect from a flow calibration? What kind of performance should the customer expect or accept from an ultrasonic meter? What are the diagnostic capabilities inherent in an ultrasonic meter? These areas, as well as others will be explored and considered
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Document ID: 70F21DB2

Statistical Control Of Meter Factors - A Simplified Approach
Author(s): Dan Comstock
Abstract/Introduction:
This paper will give a brief overview description of a simplified method for monitoring the performance of a flow meter and performing the same exercise on each meter in the system. The idea is to provide graphical assistance, through the use of meter factor control charts in: (a) developing preventive maintenance programs (b) heightening awareness of alarm situations, and (c) reducing risk to the financial bottom line. Meter factor control charts and logs make it easier to prepare reports to maintenance, operations, financial and executive managers from time to time and furthermore, they make it easier for the target audience to digest the points being made
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Document ID: D12F8278

Troubleshooting Liquid Pipeline Losses And Gain
Author(s): Joseph T. Rasmussen Michael R. Plasczyk
Abstract/Introduction:
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.
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Document ID: D3F2DD2F

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: 0BA6A83B

In-Situ On-Site() Gas Meter Proving
Author(s): Edgar B. Bowles, Jr
Abstract/Introduction:
Natural gas flow rate measurement errors at field meter stations can result from the installation configuration, the calibration of the meter at conditions other than the actual operating conditions, or the degradation of meter performance over time. The best method for eliminating these or other sources of error is with in-situ (on-site) calibration of the meter. That is, the measurement accuracy of the field meter station should be verified under actual operating conditions by comparing to a master meter or prover. Field provers have been developed for operation at high line pressures and flow rates. For purposes of this discussion, a high gas flow rate is any flow greater than 3,000 actual cubic feet per hour or (85 m3/h) at pressures to 1,440 psig (10 MPa). A field meter prover may be either a primary flow standard or a secondary flow standard. A primary flow standard is any measurement device that determines the gas flow rate from the fundamental physical measurements of mass (M), length (L), temperature (T), and time (t). Measurement devices based on other techniques or methods are categorized as secondary flow standards. For highest accuracy, a secondary flow standard (sometimes also called a transfer standard) must be calibrated using a primary flow standard at operating conditions. Two comprehensive reports on the subject have been produced by Park, et al.,1 and Gallagher.2 Much of the following information is referred to in detail in these reports.
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Document ID: 5249EA5C

Ultrasonic Meters For Liquid Measurement
Author(s): Soovo Sen
Abstract/Introduction:
Ultrasonic liquid flow meters have been in use in the industry for some time now. The first use of ultrasonic meters for liquid measurement dates back to the use of insertion type transducers in the trans-Atlantic pipeline for leak detection purposes. Since then, various types of ultrasonic meters have been available to help customers efficiently measure flow through pipelines. With progress in time, ultrasonic flow meters became more accurate and, in the early 1990s, ultrasonic flow meters were first used for custody transfer applications providing measurement accuracies of 0.15%. Now in the 21st century with the advancement of microprocessors, flow meters have become more refined and offer extended diagnostic capability, thus reducing significant downtime and helping customers resolve issues much faster. This paper discusses the ultrasonic technology for measuring liquid and describes the types of meters that are available now for use in various applications.
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Document ID: 488EE757

Lact Unit Proving-The Role Of The Witness
Author(s): Raymond Gray
Abstract/Introduction:
LACT Lease Automatic Custody Transfer A LACT unit automatically transfers liquid hydrocarbons from a lease to a connecting pipeline. Custody transfer means that the ownership of the product changes here, so we are talking about the cash register. LACT meters are expected to provide a high degree of accuracy. Positive displacement, turbine, and coriolis are the most widely used meter types for custody transfer. A witness must be aware that certain process variables, such as temperature, rate, and viscosity changes will affect different types of meters differently
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Document ID: 07BA67C5

Liquid Flow Provers
Author(s): Nick Thurlby
Abstract/Introduction:
The purpose for proving a meter is to calibrate the flow measured by a meter. Usually there are multiple parties involved in any fluid transfer. There is a seller, a buyer, and usually a middle, nonbiased, third party. The necessity of proving a meter depends on the value of accurate measurement for the product being handled. The ability to test a meters accuracy is vital to petroleum measurement. The objective of proving a meter is to determine each individual meters factor
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Document ID: 9FE47B07

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: AA854EAF

Measuring High Viscosity Liquids With Flow Meters
Author(s): Stephen T. Steve() Stark
Abstract/Introduction:
Measuring higher viscosity hydrocarbon liquids is much more interesting than measuring lower viscosity liquids for a number of very good reasons including those addressed in many published technical papers and articles. Although several different types of meters are typically discussed, quadrant-edged orifice meters are often not included in the mix. Compared to some of the more commonly used viscous flow meters, quadrant-edged orifice meters have no moving parts, are fairly inexpensive, reliable, and non-proprietary.1 As originally reported in Washington, DC in 1986 during the First International Symposium on Fluid Flow Measurement (ISFFM), a series of controlled tests performed in 1985 demonstrated the excellent characteristics of quadrant-edged orifice meters when used to measure viscous oil flowing at low Reynolds numbers and compared results to earlier work on the subject
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Document ID: 7E537794

Proving Liquid Meters With Microprocessor Based Pulse Outputs
Author(s): Matthew Mihalcin
Abstract/Introduction:
Is there a fundamental issue with the operation of Coriolis flowmeters and Ultrasonic flow meters (UFMs) that proving them difficult or impossible for certain applications? Experience has shown that some applications of these meters have had proving experiences that range from plain difficult to outright frustrating. These newer technologies use microprocessors to control their electronics, to communicate diagnostics, to sample their respective sensors, to compute the flow and to output volume/mass pulses. Because of this common dependence on the microprocessor, these two technologies, the UFM and Coriolis meters, will be collectively referred to as microprocessor based meters (MBM) to emphasize this common design characteristic
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Document ID: 95314AD6

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: 4F4A4437

Liquid Meter Proving Techniques
Author(s): J. H. Harry() James
Abstract/Introduction:
bottom line depends on it. As a result, measurement accuracy is being scrutinized more vigorously than in the past. Companies are being required to Verify their metering accuracy. Therefore it is essential that all procedures and auxiliary equipment be operated in a defendable manner. In addition, meters are not always in clean product service and could be subject to severe wear. Even meters in clean service will experience wear over time. To ensure meters give accurate results requires regular precision calibration by a prover operated by a competent individual. Meter proving is the means by which meters are calibrated to provide a factor that can be applied to the metered output that will result in a recorded volume that can be traced back to a regulated standard. This is accomplished by passing an identical volume of liquid through both the meter and the prover. The prover is precisely calibrated using regulated standards.
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Document ID: 73F96F59

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: 706CBA04

Offshore Liquid Fpso Measurement Systems
Author(s): T. Cousins
Abstract/Introduction:
Floating production, storage, and offloading systems (FPSOs) receive crude oil from deepwater wells and store it in their hull tanks until the crude can be pumped into shuttle tankers or oceangoing barges for transport to shore. They may also process the oil and in some later FPSOs to be used for Gas distribution. Floating productions systems have been utilized in remote offshore areas without a pipeline infrastructure for many years. However, they have become even more important with the push by the offshore industry into ever deeper waters. Floating production, storage, and offloading/floating storage and offloading (FPSO/FSO) systems have now become one of most commercially viable concepts for remote or deep-water oilfield developments. They also allow a company to develop offshore resources quickly between discovery and production. They have been shown to reduce this time as much as two to four years. Further there can be significant cost savings in developing marginal fields
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Document ID: 0E8C29F1

Operational Experience With Small Volume Provers And Water Draws
Author(s): Kevin Fields
Abstract/Introduction:
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: A932675B

Applications In Liquid Measurement Using Clamp-On Ultrasonic Technology
Author(s): Sid Douglass
Abstract/Introduction:
custody transfer measurement by Ultrasonic Meters with the publication of Chapter 5.8 in 2002 the fact remains that ultrasonic technology has been around for many years. Working for Mid-Valley Pipeline in 1982 I can remember my first encounter with an Ultrasonic meter or in this case a densitometer. Yes the densitometer did work and did what it was supposed to do. The one problem however was the densitometer was an insert ultrasonic instrument and Mid-Valley was a crude oil pipeline. Simply put, in the winter time when the paraffin really began forming on the pipe wall and scrappers were being run every week on the north end, it was noticed that the densitometers, the insert ultrasonic ones, started having problems. After waiting 2 or 3 days to see if the problem would correct itself, we often found ourselves scheduling maintenance time to pull the densitometer and clean the sensing element. Granted it has been a few years but I remember thinking this was not bad technology, it just was not applied as well as it should have been. This introduction was started however talking about this new technology called ultrasonic and yet my first experience with it was in 1982, almost 30 years ago. Well, as one might suspect it gets one to thinking about ultrasonic technology and when it might have first been proposed for the measurement of flow in pipes. Some may not believe it but the first patent issued I know of was in the late 1800s in Germany. While it is safe to assume no meters were made at that time using this new principle it can not be denied the principle existed then.
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Document ID: 80BCEBE9

Measurement Of Liquefied Petroleum Gases Lpgs()
Author(s): Brent H. Palmer
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: F53D864E

Proving Coriolis Meters
Author(s): Marsha Yon
Abstract/Introduction:
Coriolis meters are in use throughout the hydrocarbon industry for the measurement of fluids including crude oil, products such as fuel oil, gasoline, and diesel, and light hydrocarbons such as natural gas liquids, propane, etc. When used for custody transfer, it is most often required by contract between the buyer and seller that the meter be proven in the field on the fluid that is being measured and at the conditions under which it will be operating. This paper will utilize the American Petroleum Institutes Manual of Petroleum Measurement Standards (MPMS) as the reference for industry practices for field proving methods and calculations. Coriolis meters can measure volume, mass and density. If the meter is used to measure volume and the pulse output represents volume, the meter should be proven as a volume meter. MPMS Chapter 4, Proving Systems, contains information specific to volumetric proving. If the meter is used to measure mass and the pulse output represents mass, the meter should be proven as a mass meter. Currently Chapter 4 does not contain information relative to proving on a mass basis however MPMS Chapter 5.6, Measurement of Liquid Hydrocarbons by Coriolis Meter, does provide guidelines for mass proving. If the density output is used for custody transfer flow calculations, the density measurement can be proven using MPMS Chapter 14.6, Continuous Density Measurement and a pycnometer or using MPMS Chapter 9, Density Determination and a hydrometer. The temperature output of a Coriolis meter is obtained from an internal RTD which is not inserted into the fluid and thus does not meet MPMS Chapter 7, Temperature Determination requirements and should not be used for custody transfer calculations
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Document ID: A235134C

Viscosity Compensation Of Helical Turbine Meters
Author(s): Joshua Rose
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: 3F50067E

Theory And Application Of Pulse Interpolation To Prover Systems
Author(s): David J. Seiler
Abstract/Introduction:
Pulse interpolation, by definition, is the ability to estimate values of (a function) between two known values. Therefore, pulse interpolation enables pulse counts to be made to a fraction of a pulse, thus greatly reducing the rounding - off errors that occur when pulse counts are made to the nearest whole number which always happens in the absence of Pulse Interpolation
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Document ID: 183669A2

Advanced Diagnostic Measurement And Verification With Coriolis Mass Flowmeters
Author(s): Michael Keilty
Abstract/Introduction:
Electronic instruments have become increasingly intelligent. In the recent past, a sensor only transferred the measured process parameters to the Distributed Control System (DCS) in plant process applications, today sensors can measure multiple process variables, transmit internal data, and even provide information regarding their status. Digital communication, over fieldbus networks, enables the devices to provide all kinds of data, singly from each measurement point at a time. Todays data management systems have greater power to not just collect the process data and verify whether the system is within or outside acceptable limits but can also determine the reliability of the device information, its condition and whether it is in need of maintenance. Electronic instrumentation with data automation equipment has now found increased application into oil and gas field applications, replacing mechanical measurement and recording devices, and minimizing personnel needs at remote gathering points
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Document ID: 91FA786D

Advanced Application Of Flow Computers Metering, Monitoring, & Data Acquisition Systems
Author(s): Sami Halilah
Abstract/Introduction:
This paper presents information about applications of flow computers in the oil and gas industry for (a) Upstream Production, (b) Midstream Pipeline, and (c) Downstream Refining, Process plants, and Chemical Plants. Different applications in those three areas are presented in this paper. Some of the applicable standards are discussed and examples of few hardcopy print out of the flow computer are presented to provide some idea about the capabilities of the Flow Computers.
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Document ID: 8FA902D7

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: ECBAFDA9

Witnessing Orifice Gas Measurement And Field Testing
Author(s): Olen Douglass
Abstract/Introduction:
The natural gas industry is an ever changing field. While the basic concept of orifice measurement remains the same, new methods of obtaining and storing data are constantly being introduced. Because of this, the need for witnessing orifice gas measurement and field testing is more important than ever
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Document ID: 745BCCFF

Application Of Flow Computers For Gas Measurement And Control
Author(s): King Poon
Abstract/Introduction:
Flow computers are microprocessor controlled CPUs specifically designed to measure and regulate the transfer of a fluid from one point to another. They are an essential part of electronic fluid flow measurement, and are usually installed in various remote locations throughout the production, transmission and distribution segments of the gas industry. The function of a flow computer is fourfold: collect measurement data, calculate and store measurement data, transmit stored measurement data to a host system, and execute control requirements. In addition to measurement data, the event log, audit trail, and alarm information are also collected, stored, and subsequently transmitted to a host system in accordance with API Ch 21.1 - Flow Measurement Using Electronic Metering Systems. All of these flow computer functions are controlled by onboard firmware, independently or in conjunction with inputs from Host systems. It is this on-board firmware, and associated Host software, that allows the user to maximize the flow computers versatility and efficiency
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Document ID: 9BE05AB7

Improving Flow Measurements With Improved Calibration And Data Handling Procedures
Author(s): Duane Harris
Abstract/Introduction:
demanding. Every field technician is tested in both knowledge and skills on a daily basis for: ? electronic controls to pneumatic controls ? communication system support ? multiple disciplines ? support of measurement equipment ? procedures that must be followed ? regulatory requirements governing the facilities ? ongoing training of field personnel These factors and many more create a tremendous and constant challenge for every organization
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Document ID: 74D3BC18

Proving Liquid Ultrasonic Meters
Author(s): Christopher B. Laird
Abstract/Introduction:
Proving is the process that determines the accuracy of a meter. A prover is a device with detector switches that define a precise, known volume. The prover is connected in series with the meter being proved so that as flow passes through the meter, the same flow, and only that flow must pass through the prover. The flow moves the displacer in the prover until it touches the first detector switch, the pulses coming from the meter start being counted by a prover counter. When the displacer touches the second detector switch, the pulses from the meter stop being counted. In this way, the exact number of pulses generated by the meter for an exact amount of flow is determined and the actual volume registration of the meter can be compared to the known volume of the prover. The ratio of the volume of the prover to the volume registered by the meter is called the Meter Factor. The proving process involves taking the average of several tests (comparisons) of the above mentioned ratio and checking the consistency of the tests. For example, if 5 tests or proving runs are made, the ratios must agree within 0.05%. If they do, then statistically, the uncertainty of the average Meter Factor will be within 0.027% and will meet industry requirements
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Document ID: EAA5388F

Preparing A Prover For A Water Draw Calibration
Author(s): Herb Garland Dennis Kirtley
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: 4E3A475D

Laboratory Auditing
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: 918770EA

Btu Analysis Using A Gas Chromatograph
Author(s): Michael Gaura
Abstract/Introduction:
Prior to 1978, most custody transfer of natural gas contracts were based on the volume of gas being transferred between the parties. In 1978, congress passed the Natural Gas Policy Act that mandated the custody transfer of natural gas based on the energy content, creating the need to determine the energy content of the natural gas at the custody transfer location. An instrument that burnt the gas and measured the heat output of the flame, a calorimeter, was then widely used to determine the energy content. In the mid-eighties, the functionality and reliability of gas chromatographs (GC) began to surpass the calorimeter and the GC eventually took over the energy measurement role to become the most common method for determining the energy content of the gas. This paper will provide an overview of the considerations for online measurement of BTU and how the GC calculates the energy content
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Document ID: EFA6BEB5

Btu Determination Of Natural Gas Using A Portable Chromatograph
Author(s): Burt Reed
Abstract/Introduction:
The analysis of natural gas by using a gas chromatograph has become the one of the most important components in gas measurement in todays energy industry
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Document ID: 3C98E578

Chromatograph Applications And Problems From A Users Standpoint
Author(s): Fred Ryel
Abstract/Introduction:
Chromatographs are available for all types of applications in the natural gas industry. The main applications that this class will discuss are: process monitoring of liquids and gases, environmental flares and ambient air, landfill gas and contaminates. These can also include corrosives such as H2S, CO2 and O2, etc. Regardless of the application, the main priority is to capture an accurate sample and not change the properties before it can be analyzed. Maintaining the sample integrity is by far the most difficult process. The procedure of acquiring the sample and the way it is analyzed depends upon the media being sampled
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Document ID: 19F30332

Chromatograph Maintenance And Troubleshooting
Author(s): Michael Gaura
Abstract/Introduction:
Natural Gas is sold as Energy. Gas Chromatographs calculate the Energy value of the Gas (as well as other calculated values used in the Flow Calculation). When there is only a single Gas Chromatograph (GC) on a Custody Metering station, the downtime for a GC must not only be at a minimum but it should be planned ahead of time, rather than occurring only when a failure has occurred. To allow for predictive maintenance an appropriate maintenance program should be instituted so that analysis problems are identified before they cause measurement errors. Thus maintenance can be performed on a predictive basis, rather than on an ad-hoc or breakdown basis. This paper will describe the routine maintenance that should be performed on a Gas Chromatograph System, the predictive diagnostics steps that should be used, and finally outline the steps taken to perform an overhaul of the analysis system.
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Document ID: 1AE85706

Chromatographic Analysis Of Natural Gas Liquids
Author(s): Brad Vidrine
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: 6A883EA1

Crude Oil Quality - What Is Involved And Why Its Important A Pipeline Perspective
Author(s): Douglas Arrick Patti Edens
Abstract/Introduction:
Crude oil quality is important to all areas of the petroleum industry and for a variety of reasons that cross disciplines such as safety, enhanced production, pipeline hydraulics or pumpability, refinery operations and regulatory compliance. Pipelines are in the center of crude oil quality. Knowledge of crude oil quality is both important to pipeline operations and to ppipeline customers. Some knowledge of the aspects of crude oil quality all the way from well (production) to wheels (refinery finished products) is necessary to understand the importance of protecting crude oil quality in the transportation system. When we understand our needs as well as the needs of our suppliers and end users, we can begin to appreciate the importance of all of the testing and communications we must consider from our middleman position on pipelines
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Document ID: 93BA38D8

Determination Of Hydrogen Sulfide And Total Sulfur In Natural Gas
Author(s): David Haydt
Abstract/Introduction:
Hydrogen sulfide and other sulfur bearing compounds exist naturally in many natural gas fields throughout the world. It is generally necessary to remove these sulfur bearing compounds from the gas in order to preserve public safety, reduce corrosion in pipelines, meet contractual agreements and to control odor in the gas. Thus the determination of hydrogen sulfide and total sulfur in natural gas is critical to the natural gas industry
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Document ID: 465C1005

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 presents a challenge for the measurement of moisture
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Document ID: 1A7B8A49

Determination Of Hydrocarbon Dew Point In Natural Gas
Author(s): Jack Herring
Abstract/Introduction:
The focus of this paper is to identify the major factors that contribute to best practices for measuring the hydrocarbon dew point (HCDP) in natural gas. The three most popular methods for measuring this parameter will be discussed. These three techniques are: Manual visual method with a chilled mirror dew point instrument Equation of state calculations from analysis by chromatography. Automatic optical dew point instrument. Pros and cons for each technique will be listed that will provide a basis for comparing these three methods of measurement for this important parameter. The Best Practices for making this critical measurement using any of the techniques above will be discussed. The quantifiable financial impact of this measurement will be shown
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Document ID: B8F105C5

Hydrocarbon Dew Point Effects On Gas Flow Measurement
Author(s): Fred Van Orsdol
Abstract/Introduction:
The hydrocarbon dewpoint (HCDP) of interest to the natural gas industry is simply an operating condition that causes liquids to condense out of the gas stream and form a liquid phase. Normal condensation occurs when increasing pressure or decreasing temperature causes liquids to form. Retrograde condensation occurs on a different portion of the phase envelope, when 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: B1803453

D.O.T. Requirements For The Transportation Of Sample Cylinders
Author(s): David J. Fish
Abstract/Introduction:
The United States Department of Transportation (D.O.T.) is a department of the U.S. Federal Government which oversees all issues regarding transportation within the United States of America and U.S. Territories. Its influence around the world is great and widely respected, but its jurisdiction and power of enforcement is limited to the USA and its territories. As regards this paper, we will discuss the D.O.T. and its involvement surrounding sample cylinders for the hydrocarbon industry and the rules regarding the movement of these cylinders from point to point in the United States. The most important statement to be made is that the D.O.T. and Code of Federal Regulations, Title 49 (CFR-49) is the definitive and final authority on all issues regarding the handling and transportation of sample cylinders. Much has been written and quoted over the years and many regulations have changed over the years. It is the sole responsibility of each company involved with sample cylinders, to have a copy of CFR-49 and to be responsible for clarification of any issues they have, by researching CFR-49 and consulting with D.O.T. representatives. They have the final word on any questions. D.O.T. is the enforcement agency regarding sample cylinder transportation. The author of this paper and the company he represents do not present themselves as authorities on this matter for you or your company. This paper is presented for the sole purpose of providing limited information and to encourage you and your company to become better informed for your specific needs and operations
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Document ID: 44C96FD0

Energy Measurement Using Flow Computers And Chromatography
Author(s): Burt Reed
Abstract/Introduction:
The means and methods of transfer of quantities of natural gas between buyers and sellers have been changing for many years. When coal gasification was used to fuel the streetlights in Atlanta, Ga. There was no reason to even measure the commodity. The municipality generated the gas, transported it, and burned it. When Frank Phillips started purchasing gas rights back in the 1930s, every one thought he was more than odd. Natural Gas was considered at that time a messy by-product of oil production that had to be disposed of. Even during the 1960s natural gas was still being flared at the wellhead in Oklahoma. During the 1940s, it was said that one could drive from Kilgore, Texas to Tyler, Texas at night without turning on the head light on your car due to all the gas flares. In this economic environment, measurement was not an issue if you could sell the gas at all it was considered a business coup. Even then, a good price was 2 cents an MCF. But when Henry Ford was building the Model T, gasoline was a refinery waste product that the heating oil manufacturers were glad to get rid of. Not so now. So, as with other cheap forms of energy, both the use and the infrastructure for natural gas grew. Natural Gas prices were tied to oil prices very tightly until the 1990s. If oil went up, so did Natural Gas. When it went down, down came the gas prices. Even though many electric power plants had been built with the capability to burn multiple sources of energy, like coal, oil and Natural Gas, the increasing pressure to clean up the environment, caused Natural Gas to become the preferred energy source. This factor plus the maturing pipeline infrastructure have now led to Natural Gas becoming its own independent commodity.
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Document ID: D802245C

Energy Measurement Using Ultrasonic Flow Measurement And Chromatography The Technicians Perspective
Author(s): Charles W. Derr
Abstract/Introduction:
The demand for global energy increases with time as surely as the world population of users of gas energy has increased each year. Energy will ALWAYS be in demand. Good Systems for measuring it accurately and reliably are a Must. This paper will put some of the realities of assembling and operating an Energy Measurement Station for natural gas into perspective into A Technicians perspective
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Document ID: 725EDEE8

Field And Laboratory Testing Of Sediment And Water In Crude Oil
Author(s): Jane Williams
Abstract/Introduction:
The quantity of sediment and water in crude oil must be accurately established as part of the custody transfer process. Purchasers only pay for the crude oil received, and want to minimize the quantity of sediment and water they must dispose of. Consequently, monitoring of the sediment and water content is performed at the production site to prevent excessive sediment and water entering the pipeline system. The quantity of sediment and water a pipeline is willing to accept into their system depends on geographic location, market competitiveness and their ability to handle the sediment and water in the system. Each pipeline publishes the quantity of sediment and water it will accept.
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Document ID: A0451120

Fundamentals Of Gas Chromatography
Author(s): Merle Bell
Abstract/Introduction:
Btu is the three letter acronym for British thermal unit. One Btu is the quantity of heat required to raise the temperature of one pound of water from 58.5 F to 59.5F (about 1055.056 joules (SI)). Heat (Btu), is gained from the burning of Natural Gas otherwise known as Oxidation, which is shown in the chemical equations below: ? CH4 + 2O2 CO2 + 2H2O + HEAT (1010 Btu/CF) ? 2C2H6 + 7O2 4CO2 + 6H2O + HEAT (1769 Btu/CF) ? C3H8 + 5O2 3CO2 + 4H2O + HEAT (2516 Btu/CF) This HEAT is the valuable commodity that makes Natural Gas production, transmission and distribution profitable as an enterprise. The purpose of this paper is to describe how this heat amount can be obtained from the gas composition. The method for attaining this composition will also be discussed. Gas chromatography is today being chosen more and more in the natural gas industry for monitoring of gas quality. The calculations of the gas volumes in modern electronic flow meters requires not only Btu information, but specific gravity, Mol. % CO2 and Mol. % N2 as well. In addition, the current AGA-8 compressibility equations for the detailed method of calculation of Fpv,, the AGA 10 Speed of Sound equations and the SRK and Peng-Robinson Hydrocarbon Dew Point (HCDP) calculations also require a complete analysis. In the past, on line calorimeters were used to obtain heating value, but today, modern micro-packed columns are providing faster cycle times for time critical Btu measurement applications. For these reasons mentioned above, and the fact that the installation requirements for chromatographs are less stringent than calorimetric methods, the use of gas chromatographs has become standard practice
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Document ID: 504B2866

Heat Quantity Calculation Relating To Water Vapor In Natural Gas
Author(s): Edgar B. Bowles, Jr Darin L. George
Abstract/Introduction:
Natural gas oftentimes contains some amount of water, in either vapor or liquid form. The solubility of water in natural gas flowing through a pipeline is a function of the pressure and temperature of the flow stream. The amount of water affects the heating (calorific) value per unit volume of natural gas. The more water present in the gas, the less valuable it is as a fuel, since the water does not burn. This water, in vapor form, is sometimes referred to as spectator water and it displaces the hydrocarbon components in a natural gas mixture. The net effect is a reduction in heating value and monetary value per unit volume of gas. The amount of water vapor contained in a natural gas mixture is customarily expressed in terms of the mass of water per unit volume of gas for example, pounds mass of water per million standard cubic feet of natural gas (lbm/MMSCF)
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Document ID: 0447D926

Validating Laboratory Gas Analyses
Author(s): Fred G. Van Orsdol
Abstract/Introduction:
What do you do I someone asks you to collect a natural gas sample? 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? Overview Sample System Location Sample System Design and Operation Field Sampling Procedures Sample Collection Equipment and Procedures Sample Identification Sample Transportation Receiving Samples at the Lab Inspecting and Pre-conditioning Samples Sample Injection System GC Performance Verification Calibration Standards - Preparation and Use Data Verification / Data Mapping Six Sigma Processes Sample System Location Guidelines 1. Close to the meter, preferably just downstream of it, with at least 5 nominal pipe diameters (5D) of straight run before the sample point. 2. No obstructions to flow are allowed in the upstream section before the sample point. 3. No fittings or obstructions should be located within about 3D downstream of the sample point. 4. Sample points upstream of the meter are acceptable (not preferred), but must not be in the engineered upstream section of the run, where it would only constitute a flow disturbance and destroy the integrity of the meter run. In this figure, what deficiencies do you see? 1. No Probe 2. horizontal tap 3. No heat 4. No insulation
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Document ID: 19036AD4

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: 1AC8C94D

Sampling And Conditioning Of Natural Gas Containing Entrained Liquids
Author(s): Donald P. Mayeaux
Abstract/Introduction:
The monetary value of natural gas is based on its energy content and volume. The energy content and physical constants utilized in determining its volume are computed from analysis. Therefore correct assessment of the value of natural gas is dependent to a large extent on overall analytical accuracy. The largest source of analytical error in natural gas is distortion of the composition during sampling. Sampling clean, dry natural gas, which is well above its Hydrocarbon Dew Point (HCDP) temperature, is a relatively simple task. However, sampling natural gas that is at, near, or below its HCDP temperature is challenging. For these reasons, much attention is being focused on proper methods for sampling natural gas which have a high HCDP temperature. This presentation will address problems associated with sampling natural gas which is at, near, or below its HCDP temperature. Various approaches for solving these problems will also be discussed.
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Document ID: 28D0820D

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: 32AA1EA8

Techniques Of Natural Gas Composite Sampling
Author(s): Kevin Gainey
Abstract/Introduction:
In todays competitive market, a producer of natural gas must strive to maximize their market value and achieve the highest return of invested income. In order to accomplish this goal they must ensure they are receiving full value for the natural gas products they produce. In addition to the producer, it is extremely important for the other stakeholders, whether they be government, gathering system operator, processor, or transporter to do their due diligence to ensure they are also receiving or properly accounting for the true and full value of the natural gas products that pass through their systems. Royalty rates, transportation levies and processing fees are based on the value of the natural gas being commercially bought and sold, processed or transported
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Document ID: B718B42A

Techniques Of Gas Spot Sampling
Author(s): Shannon m. Bromley
Abstract/Introduction:
This paper will provide an overall view of the spot sampling task, identify the most significant factors which impact spot sampling, and offer recommendations. It will also acquaint the reader with the components used in the spot sampling process and introduce the GPA 2166 and API 14.1 standards. The main objective of the paper is to encourage the reader to approach the spot sampling task from a scientific standpoint rather than the blind cookie cutter approach.
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Document ID: B5905394

Determining Hydrocarbon Dew Point Per Gas Chromatographic Analysis And Equations Of State
Author(s): Michael Gaura
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.
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Document ID: AD040ACA

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
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Document ID: 6D16FD44

Moisture Measurement Using Laser Spectroscopy
Author(s): Ken Soleyn
Abstract/Introduction:
Tunable Laser Diode Spectroscopy (TDLAS) is rapidly becoming the measurement technology of choice for continuous online moisture measurement in natural gas. Natural gas is dehydrated and treated prior to transportation and use. The removal of water from natural gas is of considerable costs to the supplier and consumer. Reducing dehydration costs is a tradeoff between profits and the reduction of gas quality. Water increases maintenance cost within the gas pipeline infrastructure. Water vapor present in excess amounts in natural gas results in pipeline and component corrosion, can cause ice buildup, methane hydrate formation, lowers the calorific value and increases the energy consumption for compression and transportation. No technology is without limitations however TDLAS technology offers several advantages over the other types of sensor-based system including fast response and long-term stability. This technology does not rely on a wetted moisture sensing surface. Light energy transmitted through an inert sample cell is the basis of the measurement. The fundamental principle of measurement is based on the Beer-Lambert law which relates the concentration (mole fraction) of a specific gas in gas media to the absorption of light at a specific frequency
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Document ID: 2B2ADC77

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: 749DCD7F

CO2 Determination Of Natural Gas Streams
Author(s): Charlie Cook
Abstract/Introduction:
Carbon Dioxide is measured in Natural Gas for two reasons. First and most often it is measured for energy determination (BTU/CV) by gas chromatography. And the second reason CO2 is determined is for pipeline integrity. The measured data is transmitted in various ways for records keeping as well as operational input. CO2 measurement for energy determination is typically made by gas chromatography. Gas Chromatography is employed in two ways - on line gas chromatography which is used primarily for custody measurement in larger meter stations or by laboratory measurement of composite samplers. CO2 determination is useful or even required as upstream and downstream companies attempt to manage their operations more effectively. Priorities vary among these companies as well as budgets. Therefore each method may be justified by specific operation needs to be discussed later.
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Document ID: 9CBC10D4

Considerations In Sampling Wet, High Pressure Or Supercritical Natural Gas
Author(s): James N. Witte
Abstract/Introduction:
This paper discusses the problems encountered during online sampling of wet, high pressure and supercritical natural gas for subsequent compositional analysis. It provides solutions and comments on how they relate to the API and GPA industry standards for natural gas sampling. The paper also discusses the use of phase diagrams in the design and operation of a natural gas sampling system. The phase diagrams presented in this paper were calculated using a commercial software program intended for that purpose. The Peng-Robinson Equation of state was utilized by the software to compute pressures and temperatures necessary to construct each phase diagram presented. The gas compositions considered in this document were either taken from AGA Report 81 or from actual gas sample analyses. The Joule Thomson coefficient was calculated from a molar gas analysis using Refprop 23 version 9.0 which is available from NIST2. The term wet gas as used in this paper refers to a flowing natural gas stream, having both a vapor and liquid phase at equilibrium conditions determined by pipeline conditions. The gas is assumed to have been dehydrated and has a water content of less than 7 pounds per million standard cubic feet of gas
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Document ID: 492FD05E

Ultrasonic Flow Meter Compliance With API 14.10 Measurement Of Flow To Flares
Author(s): John Chitty
Abstract/Introduction:
Ultrasonic flow meters have been used for over 20 years to measure flow to flare stacks. Due to changes in plant construction philosophies to more compact building, environmental regulations, and an increased offshore activity the demands to these measurements have changed during recent years. New regulations implemented in Europe and North America requires the measurement of fuel and flare gas to calculate CO2 and VOC emissions. Compact and more optimized production facilities have higher capacities and therefore result in higher maximum flow conditions over the flare. Flow rates of more than 100 m/s have been recorded during shut down conditions. Waste or flare gas can vary greatly in its composition and abrupt flow condition changes should be expected. Furthermore the low flow conditions became more important to identify valve leakage in normal operational conditions. Minimum flow rates demand advanced signal processing algorithms to ensure exact and high resolution time measurement. High flow velocities will introduce soaring noise within the flowing gas and at the ultrasonic probe itself. Even drift of the ultrasonic beam has to be considered at high gas velocities. With all of these considerations, the main guidance for flare flow installation is API 14.10
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Document ID: 43383808

Micro Gas Chromatography For Liquid Petroleum Gass
Author(s): Amorin A. Dagostaro L. Diersche Y., Gonzalez A.
Abstract/Introduction:
For years, microGC analysis has been useful as a powerful tool for the fast and reliable analyses of natural gas and other gaseous matrices but, it is yet to prove its capabilities for liquid samples. In this paper, we present a unique gasifying system for volatile liquid sample introduction in a microGC. The system has been tested with a wide range of different samples: liquefied gases (ethane/propane blends, volatile liquids (natural gasoline from fractionation plants), butane blends and samples with olefins and C6+s. Due to the different nature of the samples, a single point calibration was used. The system was designed for simple operation and maintenance, reducing time and increasing ease of operation when compared to regular Gas Chromatography analyses. All the samples were handled in the same way with the only variation being the response factors applied to each type of sample. Repeatability data will be presented from both calibration standard blends and from real world samples. Also presented are comparisons of the microGC results with conventional GC data.
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Document ID: 4DA6B6EE

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: 361B6682

Causes And Cures Of Regulator Instability
Author(s): William H. Earney
Abstract/Introduction:
This paper will address the gas pressure reducing regulator installation and the issue of erratic control of the downstream pressure. A gas pressure reducing regulators job is to manipulate flow in order to control pressure. When the downstream pressure is not properly controlled, the term unstable control is applied. Figure 1 is a list of other terms used for various forms of downstream pressure instability. This paper will not address the mathematical methods of describing the automatic control system of the pressure reducing station, but will deal with more of the components and their effect on the system stability.
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Document ID: 0DBC4934

Controlling Surges In Liquid Pipelines
Author(s): Clayton Carroll
Abstract/Introduction:
Numerous technical papers have been written on unsteady state surge flow or water hammer. This paper, unlike many of its predecessors, will present a view adapted to the engineer/technician who, for one reason or another, only needs a basic understanding of why surge occurs and how to control it.
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Document ID: 336107C1

Overpressure Protection Methods
Author(s): Thomas Weyer
Abstract/Introduction:
Overpressure protective devices are of vital concern to the gas industry. Safety codes and current laws require their installation each time a pressure reducing station is installed that supplies gas from any system to another system with a lower maximum allowable operating pressure. The purpose of this article is to provide a systematic review of the various methods of providing the overpressure protection. Advantages and disadvantages of each method are evaluated, and engineering guidelines are provided
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Document ID: 91969E80

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: 2ACD326F

Selection, Sizing, And Operation Of Control Valves For Gases And Liquids
Author(s): Ross Turbiville
Abstract/Introduction:
Proper control valve sizing and selection in todays industrial world is essential to operating at a cost-effective and highly efficient level. A properly selected and utilized control valve will not only last longer than a control valve that is improperly sized, but will also provide quantifiable savings in the form of reduced maintenance costs, reduced process variability, and increased process availability. An undersized valve will not pass the required flow, while a valve that is oversized will be more costly and can cause instability throughout the entire control loop.
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Document ID: 3AF9FDB8

Turbulence And Its Effects In Measuring And Regulating Stations
Author(s): Terrence A. Grimley Edgar B. Bowles, Jr
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: F3DFF0BD

Flow Meter Installation Effects
Author(s): Edgar B. Bowles, Jr
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.
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Document ID: 2879536A

Allocation Measurement - API Chapter 20.1
Author(s): Mark Davis
Abstract/Introduction:
The current and still in force API Chapter 20.1 Standard was last revised in 1993. This document was a very specific document on upstream allocation measurement procedures. That document will be superseded by the development of a suite of Standards and Recommended Practices being developed by the API Committee on Production Measurement and Allocation (CPMA). CPMA is a recently formed Sub-Committee under Committee on Production Measurement (COPM) with CPMA currently expanding the Chapter 20 into to a host of Sections, each with individual Working Groups writing either Recommended Practices or Standards in the Upstream Measurement and Allocation area. Once the newly revised Chapter 20 is balloted and approved by API, the existing Chapter 20.1 Standard document will be incorporated into the applicable Section of the new suite of Chapter 20 Standards / Documents, followed by sun-setting the existing Chapter 20.1 Document
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Document ID: C0446D6B

Orifice Meter Tube Dimensional Tolerances
Author(s): Ken Embry
Abstract/Introduction:
The orifice meter is the most predominantly utilized device for measurement of natural gas. Its dominant presence in the natural gas industry stems from many years of acceptance as the primary means for accurate measurement. In 2000, revised manufacturing and inspection standards, along with new technology for flow enhancement have improved the overall accuracy of orifice metering. Though other measurement devices and technologies have made significant impact, the orifice meter offers stands as the dominant device for several reasons
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Document ID: F3C4556D

Auditing Electronic Gas Measurement Per API Chapter 21.1
Author(s): Danyelle Miller
Abstract/Introduction:
Since the 1990s Electronic Gas Measurement has become more widely used than Barton chart recorders. With this comes the necessity of EGM auditing. It is rapidly transforming the element of interpretation by manual chart integrators to the evaluation of numeric data. EGM is quickly becoming the preferred method of gas measurement. Although EGM data is more accurate than chart recorders there is still the possibility of errors occurring. Therefore, EGM auditing is essential to verify the accuracy of the data that is used for volume reporting. Having all necessary data is imperative to the assessment process and is the foundation of a successful audit.
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Document ID: 3EF1B618

Auditing Gas Measurement And Accounting Systems
Author(s): John Renfrow
Abstract/Introduction:
The intent of this paper is to address the different auditing requirements of Natural Gas Measurement and most common measurement adjustment issues. The following issues should be addressed in the audit process:
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Document ID: D9946D30

Auditing Liquid Measurement
Author(s): Linda A. Larson
Abstract/Introduction:
An effective audit of liquid hydrocarbon measurement is dependent upon a solid understanding of the measurement process combined with the application of sound internal auditing principles. The quality of liquid measurement activities is contingent upon (1) the reliability of the measurement equipment and instrumentation used (2) the specific procedures and practices followed in performing the measurement activities (3) the adequacy of training and proper performance of the measurement technician and (4) the proper documentation of transactions based on a measured value. All four components must be taken into consideration when auditing liquid measurement. In addition, to ensure the efficiency of the audit process, auditors must identify those areas which present the greatest risk to the organization to achieving its goals, and concentrate audit effort on those areas.
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Document ID: 42DD6749

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: 3DA75D9D

Overall Measurement Accuracy
Author(s): Paul J. La Nasa
Abstract/Introduction:
This paper presents methods for determining the uncertainty of both differential and positive metering stations. It takes into account the type of meter, number of meters in parallel, type of secondary instruments, and the determination of physical properties. The paper then relates this information to potential influence on system balance
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Document ID: 9379BD05

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 flowmeters installed in the field are based on laws of physics with sensors or transducers designed to monitor the response of flow to the primary element or mechanical response of the primary element to the flowing fluid. Some common flowmeters that monitor response of the primary element to the flowing fluid are displacement meters, turbine meter, Coriolis meters, etc
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Document ID: 734CBB50

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: 70B4F64C

Calibration Using Portable Digital Pressure Indicators Capabilities, Accuracies And Field Use Of The Portable Digital Pressure Indicator
Author(s): Roger Thomas
Abstract/Introduction:
Pressure calibration is as important today as it has been for a very long time, but the way calibration is done and the equipment used to do it has changed drastically. In the past it was a standard practice to use a primary standard for pressure calibration. That standard was normally a dead weight tester or a manometer. Today with more accurate secondary standards available there is a larger choice in what can be used for pressure calibration. What is used normally will depend on the requirements that have to be met and the equipment that is available
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Document ID: 05BEBDAE

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
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Document ID: 79C67582

Dot Qualification Training For Measurement And Control Technicians
Author(s): David Wofford
Abstract/Introduction:
Measurement and control technicians must possess certain knowledge and skills in order to effectively and safely perform their required tasks. These knowledge and skill sets are obtained through education and experience. While these requirements are common to all personnel working within these areas of technical discipline, those performing safety sensitive functions on facilities regulated under the jurisdiction of the United States Department of Transportation (US DOT) are additionally required to be evaluated for these qualifications as defined within applicable regulation
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Document ID: 72B2EC3A

Interface Detection In Liquid Pipelines
Author(s): Vicky Garza
Abstract/Introduction:
The basic concept of interface detection is simple: detect and direct the flow of different fluids, or batches, through pipelines. The implementation, however, can be very complicated. The goal of interface detection is to time the switching or cut of the product in such a way that delivers the maximum quantity of product to customers without downgrading the quality of the product. Inaccurate interface detection leads to an increase in both downgraded product delivery and transmix, which requires storage and additional refining. Both significantly cut into the profit margins on delivered product
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Document ID: 0508D3B8

Multiphase Measurement
Author(s): Philip A Lawrence
Abstract/Introduction:
The measurement of hydrocarbon flows that are un-processed is becoming more widespread in the oil and gas production industry. Multiphase meters are in many cases integrated into the conceptual design of new field developments and also retrofitted in certain mature fields were required. However, the term multi-phase flow covers a huge range of flow parameters and conditions. Measuring these various flow types has proven to be a major challenge to the oil and gas industry and its operators.
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Document ID: D820CD78

Odorization Of Natural Gas
Author(s): Kenneth S. Parrott
Abstract/Introduction:
In the one hundred and thirty years, or so that we have known natural gas as a fuel source in the United States, the demand for natural gas has grown at an astounding rate. There is virtually no area of North America that doesnt have natural gas provided as an energy source. The methods of producing, transporting, measuring, and delivering this valuable resource have advanced, and improved in direct relation to the demand for a clean burning and efficient fuel. While todays economic climate determines the rate of growth the gas industry enjoys, in a broad sense, natural gas is certainly considered essential and a fuel of the future
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Document ID: 18199AD1

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 discharge-coefficient 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: DF18EE16

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: A42892B4

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: 2030951A

The Role Of Blm 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.
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Document ID: 76BECF93

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: 7EB09B4D

Cone Meters For Liquid And Gas Measurement
Author(s): Richard Steven
Abstract/Introduction:
Differential Pressure (DP) meters have been used extensively since Herschel invented the Venturi meter, i.e. the original DP meter, in the 1880s. Since then there have been many different variants of DP meter appearing on the market. One of the most recent is the cone meter. The cone meter is a generic DP meter and uses the same generic DP meter flow equation as all other DP meters. All DP meter types exist on the market as they offer some advantage over the others. If a meter does not have some niche, whether it be reduced uncertainty, more reliability, wider range ability, self diagnostic capable or simply an attractive price, it would not be successful on the market. The cone meter has been steadily growing in market share for twenty years. Originally a patented device the patent expired several years ago and now the meter is a generic type offered by several suppliers
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Document ID: 4FE4C6DB

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
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Document ID: 4EDE8EA3

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
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Document ID: 74B5ED4F

Benefits Around Timely Analysis Of Measurement Data
Author(s): Brian Sowell
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
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Document ID: 0B8D3F2E

About Ishm 2011
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: AFF072F0


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