1、 Natural Gas Quality Management Manual Prepared by Transmission Measurement Committee August 2013 Natural Gas Quality Management Manual August 2013 Prepared by Transmission Measurement Committee Copyright 2013 American Gas Association 400 North Capitol Street, NW, 4th Floor, Washington, DC 20001, U.
2、S.A. Phone: (202) 824-7000 Fax: (202) 824-7082 Web: www.aga.org Catalog # XQ1303 ii DISCLAIMER AND COPYRIGHT The American Gas Associations (AGA) Operations and Engineering Section provides a forum for industry experts to bring their collective knowledge together to improve the state of the art in th
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14、 2013, American Gas Association, All Rights Reserved. iii FOREWORD Pipeline natural gas is not just methane, but rather a complex mixture of hydrocarbon and inert gases, sulfur compounds, moisture, and other trace constituents and contaminants. These numerous constituents form the basis of physical
15、and chemical relationships that further define natural gas as a product. To this end, it is important to understand what is implied by the word “quality.” In the traditional sense, “quality” implies excellence or superiority. However, when speaking in the context of “natural gas quality,” the word “
16、quality” simply means any of the features that describe the chemical or physical characteristics of natural gas. The subject of natural gas quality has received a great deal of attention by all industry sectors, from the wellhead to burner tip. Although many technical and policy references are avail
17、able, examination of these resources revealed an information gap in the area of the practical gas system operating concerns and management planning. This manual is intended to bridge that gap. This single-source, easy-to-use reference tool provides an overview of the technical considerations for gas
18、 quality management planning. It combines concepts from several resources to help piece together the gas quality puzzle and enhances the understanding of the comprehensive set of dependent and independent variables that define the term “gas quality.” It is generally recognized that a “one-size-fits-
19、all” solution to gas quality management and planning is impractical if we are to balance the concerns of maximizing supply while minimizing impacts on gas transportation and end use. This manual highlights the technical considerations to establish reasonable and practical gas quality management guid
20、elines to ensure this balance is realized, while continuing the natural gas industrys rich history of providing a safe, reliable, environmentally responsible, and cost-effective product to our customers. Much of the information contained in this manual is found in a variety of existing technical res
21、ources. A list of these resources, although not complete, is included in this document. This manual is a compilation of publicly available technical literature, Internet information, and opinions of researchers and other experts in the industry. The industry as a whole is still learning about gas qu
22、ality and its effects on pipeline infrastructure and end use. It is in the industrys best interests to continue research and dissemination of available history and experience. Even though attempts were made to gather information from reliable sources and correctly interpret it, this information shou
23、ld be used only for educational purposes. More in-depth analysis may be required to address specific situations within your company. iv ACKNOWLEDGEMENTS The Gas Quality Management Manual was developed by a Task Group of the American Gas Associations Transmission Measurement Committee under the joint
24、 chairmanship of Henry W. (Hank) Poellnitz III, P.E., Kinder Morgan (formerly El Paso Pipeline) and Robert D. (Bob) Wilson, National Grid, with substantial contributions from Edgar B. Bowles, Jr., Southwest Research Institute. Individuals who made considerable contributions to this document are Joe
25、Bronner, Pacific Gas water and/or water vapor (H2O); sulfur compounds, such as hydrogen sulfide (H2S), mercaptans, and derivatives; trace volatile metal compounds; bacteria; and other particulate matter. Pipeline natural gas (sometimes also referred to as “processed natural gas”) is composed primari
26、ly of methane (CH4); however, it does contain other alkane hydrocarbons, typically measured through hexane (C6H14). In contrast, unprocessed natural gas typically has greater concentrations of non-methane hydrocarbons, such as ethane, propane, butanes, and pentanes. Non-hydrocarbon gases may be foun
27、d at varying levels in both processed and unprocessed natural gas. In most cases, constituents and chemical properties for pipeline natural gas can be controlled by blending or by a variety of process technologies, typically at the wellhead, in midstream operations or, in some cases, at delivery poi
28、nts and points of end use. The decision to undertake and degree of gas processing will depend on receipt and/or delivery point specifications for various gas quality constituents or parameter limits found in contracts, tariffs, or specific end-use requirements. There is not a single definition or st
29、andard for pipeline-quality natural gas in the United States. From a general industry perspective, pipeline natural gas includes gas that meets the gas quality parametric and constituent requirements agreed to by contracting parties, as described within a pipeline tariff or contract. “Pipeline-quali
30、ty gas” is a term also used by the Local Distribution Companies (LDCs). It describes gas that is successfully delivered into a market area, forming the basis of market area adjustment gas or a substitute gas that meets established gas interchangeability requirements. AGA Report No. 4A defines “pipel
31、ine quality gas” as a gas that a) can be accepted by a pipeline without causing unacceptable operational problems for the pipeline, and b) can be blended or commingled with other pipeline gas such that the levels of individual components, including contaminants, render the overall gas stream suitabl
32、e for most combustion and feedstock applications all as spelled out in a pipeline tariff or contract. Pipeline-Quality Gas can differ from pipeline to pipeline, and gas that complies with the gas quality provisions established in a pipelines tariff (or in contracts for non-FERC regulated pipelines t
33、hat do not establish gas quality provisions in a tariff) is considered to be “Pipeline-Quality Gas.” It is noted that the U.S. Environmental Protection Agency (EPA)2has specific definitions for natural gas and pipeline natural gas as it relates to defining emission limits and calculation methods for
34、 combustion processes. EPA defines “natural gas” as a naturally occurring fluid mixture of hydrocarbons (e.g., methane, ethane, or propane) produced in geological formations beneath the Earths surface that maintains a gaseous state at standard atmospheric temperature and pressure under ordinary cond
35、itions. Natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. Additionally, natural gas must either be composed of at least 70% methane by volume or have a gross calorific value between 950 and 1,100 British thermal units (BTUs) per standard cubic foot. The EPA 272.2
36、of 40 CFR, Protection of Environment, Part 72, Subpart A, Acid Rain Program General Provisions. 4 definition further states that natural gas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, producer gas, coke oven
37、gas, or any gaseous fuel produced in a process that might result in highly variable sulfur content or heating value. EPAs definition for “pipeline natural gas” is the same as it is for “natural gas” with the exceptions that it contains 0.5 grains or less of total sulfur per 100 standard cubic feet i
38、s provided by a supplier through a pipeline From a gas quality management planning perspective, it is important to understand the appropriate application of these definitions. For example, while the EPA has established specific definitions for these terms, they are defined relative to measurement te
39、chnologies and strategies employed for emission calculation guidance and do not generally apply to contracts or tariffs. 2.2 Hydrocarbon Gases A general discussion of hydrocarbon chemistry may be found in Appendix B. Pipeline natural gas is primarily composed of methane and lesser amounts of other a
40、lkane (i.e., paraffin) hydrocarbons. A host of other hydrocarbon species, such as aromatic compounds, may also exist in trace quantities. These include benzene, ethyl-benzene, toluene, and xylene (otherwise known as “BETX”), among others. Some natural gas properties are calculated by combining selec
41、ted hydrocarbons components into a group or pseudo-compound, with characteristics determined from the mix of the groups components. For example, the pseudo-compound C6+represents the sum of all hydrocarbons having a carbon number of six (i.e., hexane) and higher. Typically, C6+represents predetermin
42、ed proportions of C6, C7, and C8. A number of “default” proportions are widely used in the industry,3but none are mandated by an industry standard. If it is not possible to measure the exact percentage of each hydrocarbon component in a natural gas blend, then an appropriate compositional “split” sh
43、ould be selected. The split could be based on historical gas supplies into a particular market area or region, or some other methodology deemed appropriate. The split generally affects the accuracy of the calculated hydrocarbon dew point value much more than the calculated heating value and relative
44、 density (or specific gravity). Table 2.1 provides some insight into the variability of the compositional makeup of pipeline natural gas in North America. This table, excerpted from AGA Report No. 4A,4denotes pipeline natural gas constituent and property limit ranges found in publicly available pipe
45、line tariffs posted on FERCs website (www.ferc.gov) in March 2008. The available dataset included 138 individual tariffs spanning North America and both intrastate and interstate pipelines. Caution needs to be exercised when using the tariff value ranges given in Table 2.1. Most tariffs enforce spec
46、ifications at the pipeline receipt point. Actual delivery ranges may be narrower, depending on market area proximity relative to production, receipt points, and consequential blending associated with pipeline aggregation of supplies. This table is provided solely to illustrate components and paramet
47、ers that should be considered during contract or tariff negotiations, not to propose actual values. Also note that sulfur from odorants is not included in the sulfur compounds shown in Table 2.1. 3Example of a C6+composition split typically is referred to in the industry as “46/37/17” or 46% C6, 37%
48、 C7, and 17% C8. This proportional split varies by supply source and delivery point. 4“Natural Gas Contract Measurement and Quality Clauses,” American Gas Association, Washington, D.C., Report No. 4A, 2009. 5 Table 2.1. Tariff and Contract Constituent and Property Considerations Gas Quality Specific
49、ation Typical Range of Values Found in Tariffs Minimum Heat Content (dry, HHV) (1) Maximum Heat Content (dry, HHV) 900 - 1,000 BTU/scf 1,075 - 1,200 BTU/scf Minimum Wobbe Number Maximum Wobbe Number 1,279 - 1,340 1,380 - 1,400 Minimum Temperature Maximum Temperature 20 - 65F 80 - 140F Maximum Hydrocarbon Dew Point Cricondentherm HDP (CHDP) C4+Liquefiable Fraction (GPM) C5+ (6) C5+Liquefiable Fraction (GPM) C6+0 - 25F at either fixed or operating pressures 15 - 20F 0.75 - 1.50% 0.2 - 0.3 gallons/Mscf 0.12 - 0.25% 0.05 gallons/Mscf Maximum Water Vapor C
