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Transporte & Distribución (Pipeline)

René Becerra Matías

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Transporte & Distribución

Conocer los parámetros y características a considerar en el diseño de cañerías de transporte y distribución (ductos).

Una vez que el petroleo y el gas son localizados y el pozo

es exitosamente perforado y completado, el producto debe ser transportado a las instalaciones donde puede ser producido/tratado, alamcenado, procesado, refinado, o transferido para una eventual venta.

Un diagrama simplificado ilustra el concepto típico, y

básico “cabeza de pozo a venta”. El sistema comienza en el dispositivo de control de pozo en los brazos del arbolito de navidad e incluye el “flowline”, los equipos de producción/tratamiento/almacenaje, medición de la transferencia de custodia, y el “pipeline” de recolección ó transporte.

1.- Introducción 2.- Sistemas de Cañerías 3.- Consideraciones de Diseño 4.- Construcción 5.- PIGs 6.- Slug Catchers 7.- Testing 8.- I&C

Intro

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Concepto típico, y básico “cabeza de pozo a venta”


Sistemas de Cañerías

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Piping and Pipeline Systems Well Flowline The well flowline, or simply flowline, is the first "pipeline"

system connected to the wellhead. The flowline carries total produced fluids (e.g., oil, gas, and production water) from the well to the first piece of production equipment—typically a production separator. The flowline may carry the well-production fluids to a common production battery, a gathering pipeline system, process facility, or other.



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Piping and Pipeline Systems Interconnecting Piping Interconnecting piping includes the piping between the

various pieces of production/treating equipment such as production separators, line heaters, oil heaters, pump units, storage tanks, and gas dehydrators. The piping systems may also include headers, fuel systems, other utility piping, and pressure-relief/flare systems.



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Piping and Pipeline Systems Gathering/Sales Pipeline The pipe that delivers the well production to some

intermediate or terminal location is the gathering or sales pipeline. The gathering pipeline literally "gathers" the production from producing wells and conveys the production to a collection system, a processing facility, custody-transfer (sales) point, or other.



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Piping and Pipeline Systems Transmission Pipeline The transmission pipeline is a "cross-country" pipeline

that is specifically designed to transport petroleum products long distances. The transmission pipeline collects the specific petroleum products from many "supply" sources along the pipeline (such as gathering pipelines) and "delivers" the product to one or more end users. There are three general categories of transmission pipelines: natural gas, "product," and crude oil. Natural-gas transmission pipelines carry only natural gas. Product pipelines may carry a number of processed or refined petroleum products such as processed natural-gas liquids (e.g., butane and propane), gasoline, diesel, and refined fuel oils. Crude-oil pipelines convey unrefined crude oil from producing areas to large storage areas or directly to refineries.



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Gathering Systems The pipeline system that conveys the individual-well

production or that of a group of wells from a central facility to a central system or terminal location is a gathering pipeline. Generally, the gathering pipeline system is a series of pipelines that flow from the well production facilities in a producing field to a gathering "trunk" pipeline.

Gathering systems typically fall into one of four categories:

• Single-trunk systems with "lateral" lines from each well

production facility. • Loop systems, in which the main line is in the shape of a

loop around the field. • The multiple-trunk system, in which there are several

main lines extending from a central point. • Combinations of Categories 1 through 3.



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Gathering Systems Selection of the most desirable layout requires an

economic study, which considers many variables, such as the type of reservoir, the shape of the reservoir, the way in which the land over the reservoir is being used, the available and permissible flow rate, the flowing and shut-in pressure and temperature, the climate and topography of the location, and the primary destination of the oil or gas.

Gathering systems typically require small-diameter pipe that runs over relatively short distances. The branch lateral lines commonly are 2 to 8 in. Gathering systems should be designed to minimize pressure drop without having to use large-diameter pipe or require mechanical pressure-elevation equipment (pumps for liquid and compressors for gas) to move the fluid volume. For natural-gas gathering lines, the Weymouth equation can be used to size the pipe.



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Transmission Pipelines "Cross-country" transmission pipelines will collect the

product from many "supply" sources and "deliver" to one or more end users. There are three general categories of transmission pipelines: natural gas, "product," and crude oil. Natural-gas transmission pipelines carry only natural gas. Product pipelines may carry a number of processed or refined petroleum products such as processed natural-gas liquids (e.g., butane and propane), gasoline, diesel, and refined fuel oils. Crude-oil pipelines convey unrefined crude oil from producing areas to large storage areas or directly to refineries. Transmission pipelines will generally require much larger pipe than gathering systems. Transmission systems normally are designed for long distances and will require pressure-boosting equipment along the route.



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Onshore Pipelines

Many factors must be considered when designing, building, and operating a pipeline system. Once the basic pipe ID is determined using the applicable flow formula, the other significant design parameters must be addressed.

For U.S. applications, gathering, transmission and distribution pipelines are governed by regulations and laws that are nationally administered by the U.S. Dept. of Transportation (DOT). The regulations are contained in the Code of Federal Regulations (CFR) Title 49, Part 190[20] Enforcement Procedures, Parts 191[21] and 192[22] Natural Gas Pipelines, Part 193[23] Liquefied Natural Gas Pipelines, Part 194[24] Oil Pipelines Response Plans, Part 195[25] Hazardous Liquid Pipelines (e.g., crude oil and products), Part 198[26] State Grants, and Part 199[27] Drug Testing. The regulations incorporate the industry codes, guidelines, and standards including ANSI/ASME B31.4, B31.8, and others.

• 20· · US DOT Title 49 CFR Part 190, Pipeline Safety Programs and Rule Making Procedures. 1998. Washington,DC: US Dept. of Transportation, US Govt. Printing Office. • 21· · US DOT Title 49 CFR Part 191, Transportation of Natural and Other Gas by Pipeline: Annual Reports, Incident Reports, and Safety-Related Condition Reports. 1998. Washington, DC: US

Dept. of Transportation, US Govt. Printing Office. • 22· · US DOT Title 49 CFR Part 192, Transportation of Natural and Other Gas by Pipeline, U.S. Dept. of Transportation, US Govt. Printing Office, Washington, DC (October 1998). • 23· · US DOT Title 49 CFR Part 193, Liquefied Natural Gas Facilities 1998. Washington, DC: US Dept. of Transportation, US Govt. Printing Office. • 24· · US DOT Title 49 CFR Part 194, Response Plans for Onshore Oil Pipelines 1998. Washington, DC: US Dept. of Transportation, US Govt. Printing Office. • 25· · US DOT Title 49 CFR Part 195, Transportation of Hazardous Liquids by Pipeline. 1998. Washington, DC: US Dept. of Transportation, US Govt. Printing Office. • 26· · US DOT Title 49 CFR Part 198, Regulations for Grants to Aid State Pipeline Safety Programs. 1998. Washington, DC: US Dept. of Transportation, US Govt. Printing Office. • 27· · US DOT Title 49 CFR Part 199, Drug and Alcohol Testing 1998. Washington, DC: US Dept. of Transportation, US Govt. Printing Office.



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http://petrowiki.org/PEH:Piping_and_Pipelines








Onshore Pipelines Internationally, many countries have adopted the U.S.

regulations and the industry codes, guidelines, and standards. Some countries have different requirements, laws, and regulations, and each should be consulted prior to designing and building a pipeline. For the most part, these regulations are similar to those in the U.S., and, thus, the comments that follow, based on U.S. standards, are generally true in other countries as well. Even pipelines not specially covered by the regulations should be designed, constructed, and operated according to industry codes, guidelines, and standards, as these are based on sound engineering and operating experience.



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Costs


Consideraciones de Diseño

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Tarifas



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Costo de Servicio



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Pipe Selection and Wall Thickness.

The type of pipe and wall thickness must be determined for each application. Following the design requirements of Part 192 for natural gas, Part 193 for liquefied natural gas (LNG), and Part 195 for crude-oil and products pipelines, the pipe materials and wall thickness can be determined using the applicable formula. As discussed in Sec. 9.2, the operating pressure (maximum and normal), operating temperature, other design factors (depending upon the type of pipeline and applicable regulation), and the pipe material will determine the wall thickness.

Typically, for high-pressure pipelines, higher-grade pipe (such as API 5L, Grades X42, X52, X60, and X65) is selected because much-thinner-wall pipe can be used, which significantly reduces pipe costs. Construction-costs savings also are realized, as the welding time is reduced and material shipping/handling costs are reduced.



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Pipe Selection and Wall Thickness.

PVC, fiberglass, polypropylene, and other materials may be used in low-pressure and utility applications. ANSI/ASME B31.4, B31.8, and the DOT regulations allow the use of alternative materials in very restricted applications. However, steel pipe will be required in the majority of the oil and gas production and pipeline applications. ANSE/ASME A53[28] and A106[29] and API 5L[30] seamless, ERW, and submerged arc-welded (SAW) steel pipe are commercially available and most commonly used in pipeline systems. Seamless pipe is seldom used in pipeline applications because of the higher unit cost and limited availability. From a design and regulatory perspective, pipe made with ERWs and SAW seams is equivalent to seamless pipe and is less costly. Note: this is not true for piping systems designed in accordance with the ANSI/ASME Standard B31.3. [7]

• 28· · ANSI/ASME Standard A53, Standard for Seamless Carbon Steel Pipe for High Temperature Service. 2002. New York City: ANSI/ASME. • 29· · ANSI/ASME Standard A106, Standard for Seamless Carbon Steel Pipe for High Temperature Service. 2002. New York City: ANSI/ASME. • 30· · API Standard 5L, Specification for Line Pipe, nineteenth edition. 2004. Washington, DC: API. • 7· · ANSI/ASME Standard B31.3, Standard for Chemical Plant and Petroleum Refinery Piping. 2002. New York City: ANSI/ASME.



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Material Selection. Pipe fittings, flanges, and valves must meet the

specification and pressure class of the pipe selected for pipeline applications. The materials for pipelines commonly conform to industry codes and standards including ANSI/ASME Standard B16.5, [11] ANSI/ASME Standard B16.9, [31] ANSI/ASME Standard B31.4, [8] ANSI/ASME Standard A105, [32] ANSI/ASME Standard A106, [29] ANSI/ASTM Standard A234, [33] ANSI/ASTM Standard A420, [34] ANSI/ASTM Standard A694, [35] API Standard 6D, [36] API Standard 6H, [37] MSS Spec. 44, [38] and MSS Spec. 75. [39] Pipe fittings can be matched to the higher grade API 5L, X Grade pipe. Detailed material information is discussed in Sec. 9.6.

• 11· · ANSI/ASME Standard B16.5, Standard for Steel Pipe Flanges and Flanged Fittings NPS 1/2 through NPS 24 Metric/Inch. 2003. New York City: ANSI/ASME. • 31· · ANSI/ASME Standard B16.9, Standard for Factory-Made Wrought Steel Butt-Welding Fittings. 2003. New York City: ANSI/ASME. • 8· · ANSI/ASME Standard B31.4, Standard for Liquid Transportation Systems for Hydrocarbons, Liquid Petroleum Gas, Anhydrous Ammonia, and Alcohols. 2002. New York City: ANSI/ASME. • 32· · ANSI/ASME Standard A105, Standard for Carbon Steel Forgings for Piping Applications. 2002. New York City: ANSI/ASME. • 29· · ANSI/ASME Standard A106, Standard for Seamless Carbon Steel Pipe for High Temperature Service. 2002. New York City: ANSI/ASME. • 33· · ANSI/ASME Standard A234, Standard Specification for Pipe Fittings of Wrought Carbon Steel and Alloy Steel for Moderate and Elevated Temperatures. 2002. New York City: ANSI/ASME. • 34· · ANSI/ASME Standard A420, Standard Specification for Pipe Fittings of Wrought Carbon Steel and Alloy Steel for Low Temperature Service. 2002. New York City: ANSI/ASME. • 35· · ANSI/ASME Standard A694, Carbon and Alloy Steel for Pipe Flanges, Fittings, Valves, and Parts for High-Pressure Transmission Services. 2000. New York City: ANSI/ASME. • 36· · API Standard 6D, Standard Specification for Steel Gate, Plug and Check Valves for Pipeline Service, twenty-first edition. 1998. Washington, DC: API. • 37· · API Standard 6H, Standard Specification for End Closures, Connections, and Swivels. 1998. Washington, DC: API. • 38· · Specification 44, Specification for Steel Pipeline Flanges. 1998. Vienna, Virginia: Manufacturer’s Standardization Soc. of the Valves and Fittings Industry Inc. • 39· · Specification 75, Specification for High Test Wrought Butt Welding Fittings. 1998. Vienna, Virginia: Manufacturer’s Standardization Soc. of the Valves and Fittings Industry Inc.



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Route Selection and Survey. Route selection is very important to successful pipeline

design. Careful study of the terrain, natural obstacles (such as mountains, swamps, marshes, and rivers), manmade obstacles (such as highways, roads, railroads, and buildings), and population density is required. Topographic maps, aerial photography, satellite imagery, and property ownership maps, as well as physical inspection, are helpful aids in the routing process.



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Route Selection and Survey. Constructability is an essential consideration when

choosing the route. Typically, the minimum pipeline construction working right-of-way (ROW) for a 2-in. pipeline is 35 to 40 ft in width, and the working area should be reasonably level. Larger-diameter pipe requires wider ROW because the larger pipe requires bigger pipe-handling equipment (sidebooms), wider ditches and wider spoil piles. Eighty- to 100-ft wide construction working ROWs are typical for 4- to 12-in. pipe, and 200-ft plus construction ROW widths are common for pipe up to 30 to 36 in. The proposed route must be surveyed to determine the exact length of the proposed pipeline, determine the physical terrain, locate natural and manmade obstacles, and verify property boundaries. Once a workable route is confirmed, the acquisition of the ROW and regulatory permits begins.



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Route Selection and Survey.



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ROW. The acquisition of private and public ROW and associated

governmental permits is a major component of the pipeline process. Oil and gas leases often have provisions that allow the producer to install wells, flowlines, production facilities, and processing and storage facilities without having to acquire additional ROW or facility properties. However, producers do not have the right to cross public roads, highways, railroads, rivers, jurisdictional creeks/streams, wetlands, or pre-existing easements or ROWs. Gathering and transmission pipelines have to purchase the ROW, or easement, that is required for the pipeline system. Typically, easements, which grant the pipeline owner the right to operate and maintain the pipeline and appurtenant facilities, are purchased. In some instances, the ROW may be purchased "in fee" where the easement is acquired as a property.



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DS 24335 RASH 19960719.



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Permits and Special Considerations.

Permits are required to install pipelines across public highways, roads, streets, and any other public conveyance. The permits must be acquired from the federal, state, or local authority that has jurisdictional authority. Special easements or permits must be acquired from railroads and other pipelines as well. There are special design requirements for pipe installed across the highways, roads, streets, and railroads, which are stipulated in ANSI B31.4, B31.8, and the DOT regulations. Heavier-wall pipe (required because of lower design derating factors), casing, hydrostatic and nondestructive testing and other special requirements are stipulated in the applicable regulations, codes, and industry standards.



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Permits and Special Considerations. Special installation requirements are common, as few

highways, public roads, or streets, if any, can be open-cut and ditched. Railroads will not allow conventional, open-cut ditch installation. The pipeline must be installed by wet or dry boring methods, tunneling, or horizontal-directional-drilling (HDD) methods. These methods are described later.



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Permits and Special Considerations. Environmental requirements have a major impact upon

the pipeline industry. Pipelines can not be constructed in certain defined wetlands, marshes, swamps, rivers, creeks, or streams where the pipeline installation and operation could affect sensitive ecologies and environments. In the U.S., the U.S. Army Corps of Engineers (COE) has the primary jurisdictional authority over these areas, and other federal agencies, such as the U.S. Fish and Wildlife Service, have secondary jurisdiction. All states now have environmental or similar agencies that also have jurisdiction in many of these areas. Internationally, many countries now have laws and regulations that protect the natural resources. Historically significant sites, archeological sites, endangered species, and many other related issues require investigation before finalizing the route selection. Special permits must be acquired to work in and around sensitive areas. In the U.S., permits from COE are required for crossing of rivers, navigable streams/creeks, wetlands, and other regulated waters.



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Permits and Special Considerations.

The environmental and natural resource regulations and requirements not only apply to regulated gathering, transmission, and distribution pipelines but also apply to flowlines and production facilities constructed within oil and gas leases. The potential cost impacts of these issues must be given serious consideration in the pipeline design process.



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Corrosion Prevention.

Steel pipe and pipeline facilities must be protected from the effects of external and internal corrosion. Nonferrous piping materials, such as fiberglass, PVC, and polypropylene, do not undergo the same corrosive effects and require little attention. Industry codes and standards and the DOT regulations require that pipelines, appurtenances, and facilities be protected from the effects of corrosion. NACE has standards prescribing the corrosion protection required for pipelines—NACE Standard MR01-76, [40] RP200, [41] and RP572. [42]

• 40· · NACE Standard MR01-76, Standard Specification for Metallic Materials for Sucker-Rod Pumps for Corrosive Oilfield Environments. 2000. Houston, Texas: NACE. • 41· · NACE RP200, Recommended Practice for Steel Cased Pipeline Practices, Sec. 3 and 5. 2003. Houston, Texas: NACE. • 42· · NACE RP572, Recommended Practice for Design, Installation, Operation, and Maintenance of Impressed Current Deep Ground Beds, Sec. 3 and 5. 2003. Houston, Texas: NACE.



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Internal Corrosion.

Internal corrosion may be caused by the presence of CO2, water, H2S, chlorides (salt water), bacteria, completion fluids, or other substances in the produced hydrocarbon. When CO2 or H2S is mixed with oxygen and/or water, acids are formed that attack and destroy the steel. When CO2 or H2S is mixed with oxygen and/or saltwater, extreme corrosion occurs. Certain types of bacteria often found in producing formations can also attack and destroy the steel. Any of the internal corrosives, separately or in combination, can cause leaks and severe blowouts.



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Internal Corrosion.

The potential corrosives usually can be identified from a chemical analysis of the produced hydrocarbons. In instances where high concentrations of CO2, H2S, or other highly corrosive chemicals are present, additional pipe wall thickness may be added in the pipe design to allow for the potential corrosive effects. This is not normally recommended, as corrosion could be localized and the rate difficult to predict. In most cases, the removal of oxygen and water from the fluid is sufficient to combat potential corrosion. Where this is not practical, corrosion-inhibition chemicals, internal coatings, and corrosion-resistant materials are used.



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Internal Corrosion.

Internal corrosion also can be caused by erosion or wear. Excessively high velocities in liquid and multiphase fluid systems can erode or wear the internal pipe wall as well as fittings and valves. The conditions that cause mechanical erosion can be mitigated through proper pipe sizing and design.

The corrosive effects of the hydrocarbon fluid may change over time as the chemistry of the produced fluid changes or as bacteria develop that were not present earlier. Where unknown corrosives develop after operations have commenced, chemical treatment may be the best solution.



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Internal Corrosion. Nayyar, Mohinder L. Piping Handbook, C. Piping Systems Corrosion and Erosion Allowances Un valor nominal utilizado para tolerancias por corrosión es 1/16" (1,5 mm) para

cañerías de acero al carbono y aceros de baja aleación en servicios para hidrocarburos. Tolerancias de corrosión mayores (típicamente por encima de 1/4" -6 mm-) para estos materiales pueden ser requeridos para el caso de corrosión severa y/ó erosión según el fluído de servicio involucrado.

Smith, Peter. Process Piping Design Handbook, volume one. Chapter 2 Piping Components Material Specifications Las tolerancias de corrosión tienen incrementos usuales de 1/16" (1,5 mm), 1/8" (3

mm), ó 1/4" (6 mm) siendo muy raro que ésta exceda 1/4", debido a que un metal de mayor resistencia a la corrosión sería especificado.

Papavinasam S. Corrosion Control in the Oil and Gas Industry, Gulf P. Publishing, 2014 Chapter 6 Modeling - Internal corrosion The de Waard-Milliams models de Waard and Milliams desarrollaron el primer modelo y el más frecuentemente

referenciado para predecir la corrosión dulce. Durante el inicio de los 1970s, las fallas en líneas de transporte de gas natural húmedo conteniendo CO2 los motivaron a investigar la corrosividad del ácido carbónico. En base a sus resultados diseñaron un nomograma que ha ganado amplia aceptación como punto de inicio para predecir la tasa de corrosión de aceros al carbono en ambientes dulces.

Duncan G., Stemler P. Enhanced recovery engineering including well design, completion and production practices, World Oil 11/1995. Ambientes Corrosivos: La severidad del ambiente corrosivo depende de la presión

parcial del CO2 en la fase gaseosa, ver tabla: Presión Parcial de CO2 Severidad de la Corrosión Menor de 7 psi 0,5 atm 0,4763 bar Mediano o no corrosivo Mayor de 7 psi 0,5 atm 0,4763 bar Moderada Mayor de 30 psi 2,0 atm 2,0413 bar Alta



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Internal Corrosion.



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Cupones de Corrosion.



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External Corrosion-Underground Piping.

External corrosion affects buried pipe and above-ground pipe. Buried pipe is subjected to cathodic actions and galvanic actions. Above-ground pipe is subjected to atmospheric corrosion and galvanic actions.

Cathodic actions occur when steel pipe is buried below ground. Ferric and other materials, such as soils, have small electrical potentials. In the natural process of converting metals back to their elemental or native state, electrolytic conduction takes place. Unprotected, the steel pipe becomes an anode (positively charged) and transfers material, by means of electrons, to the cathode (negatively charged) material, which is the soil or surrounding medium. The pipe metal literally flows away by means of the electric current between the anode and cathode. Water contained in the soils and other media serves as the electrolyte to help promote the electron transfer.



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Revestimiento externo.



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Revestimiento externo.



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External Corrosion-Underground Piping.

To counteract cathodic actions, pipe is coated with anticorrosive materials and cathodic protection systems are placed on the pipeline. The coating must provide an effective "insulation" against the environment but must be tough enough to withstand the operating temperatures, be resistant to the soil, and withstand physical handling.

There are a number of coating systems that are economical and commercially available, which include extruded systems (polyethylene or polypropylene over asphalt mastic or butyl adhesives), tape coats (polyethylene, polyvinyl, or coal tar over butylmastic adhesive), fusion bonded epoxy (thin film), and coal-tar epoxy. Fusion bonded epoxy (FBE) coatings are the most popular coating systems because they are excellent insulators; are hydrocarbon, acid, and alkali resistant; are unaffected by temperature; do not require a primer; and can be applied over finished welds (field joint).



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External Corrosion-Underground Piping. Tape-coating systems and coal-tar enamel systems are

becoming less and less popular. Tape coating is difficult to apply and is especially difficult to use on large-diameter pipe. A number of tape-coated systems have experienced failures over relatively short spans of time because of improper application. Coal-tar epoxy is becoming less desirable because of some health and environmental concerns caused during application.

In addition to the anticorrosion pipe-coating systems, cathodic protection systems are added to the pipeline to protect the pipe where breaks in the coating system occur. The cathodic protection system employs either an impressed current or sacrificial anode to protect the underground pipe. The cathodic protection system reverses the electrolytic conduction process and uses an impressed electrical current or another metal object (sacrificial anode) to make the pipe a cathode.



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External Corrosion-Underground Piping. In simplified terms, the impressed current reverses the

natural flow of electrons from the pipe to the surrounding medium to prevent the loss of metal ions. The sacrificial anode made of a higher potential metal, such as magnesium, is in contact with the pipe and the surrounding medium. The anode gives up its electrons (metal) in place of the steel pipe. Sacrificial-anode systems are simpler and less expensive than impressed current systems. Onshore pipelines generally use magnesium, and offshore pipelines use zinc or aluminum anodes. Impressed current systems are much more complex and require external power sources and AC/DC power inverters or rectifiers to provide the current to the pipe. The design of cathodic protection systems requires specialized training and can be very complicated. Detailed soil surveys must be conducted to determine the electrical potential and resistivity of the soils or surrounding medium, pipe-to-soil potentials, and a number of other criteria. System design should be done by a cathodic protection expert.



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Schematic showing a differential corrosion cell

1.- Introducción

2.- Sistemas de Cañerías 3.- Consideraciones de Diseño 4.- Construcción 5.- PIGs 6.- Slug Catchers 7.- Testing 8.- I&C


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Sistema de protección catódica con corriente impresa



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Sistema de protección catódica con ánodos de sacrificio



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Galvanic Corrosion.

Another important facet of the anticorrosion system is prevention of galvanic corrosion. Galvanic corrosion is caused by the interface of dissimilar metals with different electrolytic potentials. The dissimilar metals will gain or lose electrons from or to each other resulting in one of the metals effectively flowing away and losing material. Steel pipe that undergoes abrupt changes in the medium will behave somewhat as dissimilar metals and cause galvanic actions. Pipe transitioning from below ground to above ground may experience galvanic-like corrosion. Mating materials such as carbon steel with stainless steel will cause the carbon steel to corrode.

Insulating flanges or joints can be used to counteract the effects of galvanic actions. Efforts should be made to avoid the interface of the dissimilar materials in the system design.



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Atmospheric Corrosion.

The effects of atmospheric corrosion are readily apparent. Bare steel exposed to moisture, salt, chemicals (pollution), heat, cold, or air (oxygen) will corrode rapidly. Piping and equipment exposed daily to the elements must be protected with anticorrosion coatings. Good paint coating systems, such as epoxies, and regular maintenance will normally provide adequate protection to the above-ground facilities.

Facilities exposed to severe service, such as offshore, may require more-extensive protection systems. There are a number of alternative coating systems that are discussed in the offshore pipeline section.



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Welding and Pipe Joining.

The methods used to connect the joints or pipe segments are very important and are critical to the pipeline design. ANSI/ASME Standards B31.3, [7] B31.4, [8] and B31.8, [9] as well as the DOT regulations, specify welding and joining methods for pipe. Each type of pipe material has joining or coupling methods designed to ensure that the joint is as strong as, or stronger than, pipe joint. Fiberglass, PVC, and other types of plastic pipe may have bell- and spigot-type joints that are mechanical, threaded, or glued. Polypropylene and polyethylene pipe, which is used frequently in very-low-pressure hydrocarbon applications, use a fusion-welded joint. However, the majority of the hydrocarbon pipeline applications require steel pipe.

• 7· · ANSI/ASME Standard B31.3, Standard for Chemical Plant and Petroleum Refinery Piping. 2002. New York City: ANSI/ASME. • 8· · ANSI/ASME Standard B31.4, Standard for Liquid Transportation Systems for Hydrocarbons, Liquid Petroleum Gas, Anhydrous Ammonia, and Alcohols. 2002. New York City: ANSI/ASME. • 9· · ANSI/ASME Standard B31.8, Standard for Gas Transmission and Distribution Piping Systems. 1999. New York City: ANSI/ASME.


Construcción

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For the majority of steel pipeline applications, welding is the preferred method of joining the pipe. API Standard 1104[43] and ASME Sec. IX of the boiler and pressure vessel codes specify the requirements for the welding of steel pipe. Manual and automatic welding processes are used on pipelines both onshore and offshore. Shielded metal-arc welding (SMAW), or "stick" welding, is the most common manual process used on carbon-steel pipelines, but the development and use of higher-grade carbon-steel pipe (e.g., API 5L X65 and X70) have required the development of welding processes and metallurgy compatible with the high-carbon alloys. Stainless steels and other alloys may require special welding processes.

• 43· · API Standard 1104, Standard Specification for Welding of Pipelines and Related Facilities, nineteenth edition. 1999. Washington, DC: API.


Construcción

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Welding and Pipe Joining

There are other acceptable methods for joining pipe. Steel pipe may be threaded and coupled or may have various mechanical joints. Threaded-steel-pipe application is generally limited to small diameters, 4 in. and less. Larger pipe is difficult to properly couple, and threaded line pipe in large diameter is not readily available. Fiberglass pipe used in the industry may be threaded or have solvent-welded joints. PVC may have solvent-welded joints or may have bell-and-spigot mechanical joints. Industry codes and standards, as well as DOT regulations, recognize the other joining methods but limit the use of pipe other than steel.

The development of reliable and economical automatic welding machines has had a significant impact on the pipeline industry as well. The automatic welders may be external or internal for large-diameter pipe.


Construcción

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Each weld joint must be designed and a welding procedure specification (WPS) developed for the pipe. Each WPS specifies the type of pipe to be welded (specification, grade, etc.), the type and specification the of the pipe joint [e.g., specify bevel(s), angle, shoulder, and spacing/alignment], the material thickness or range of thickness applicable, the type and size of welding rods, the position and direction of the weld, the voltage/amperage, pre-/post-heat, stress relieving, etc. The WPS must be physically proved by actually welding a test "nipple" and conducting destructive testing in accordance with the API and/or ASME requirements. Once the specification is proven, a procedure qualification record (PQR) is recorded verifying the WPS. Welders must be qualified to perform the welds in accordance with either API Standard 1104[43] or ASME Sec. IX. [15] Each welder will perform a test weld using the WPS for the pipe and will qualify under the procedure. API Standard 1104, [43] ASME Sec. IX, [15] and DOT specify and define welder qualifications.

• 43· · API Standard 1104, Standard Specification for Welding of Pipelines and Related Facilities, nineteenth edition. 1999. Washington, DC: API. • 15· · The 2004 ASME Boiler and Pressure Vessel Code, Section IX: Welding and Brazing Qualifications. 2004. Fairfield, New Jersey: ASME.


Construcción

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Pipeline Construction Process. ROW Clearing/Preparation. Before initiation of construction activities, any

sedimentation, erosion control, construction fencing, and other preparation is completed. All vegetation is cleared and grubbed, topsoil is removed (if required), and the working ROW is graded.


Construcción

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Pipeline Construction Process. Pipe Stringing. Once the ROW has been prepared, the pipe is loaded on

flatbed trucks. Before unloading, pipeline skids (typically 4-in. × 6-in. × 4-ft hardwood timbers) are dropped along the ROW to be placed under the pipe. The trucks are driven down the ROW, and the pipe is unloaded, joint by joint/end to end, by sidebooms or cranes.


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Pipeline Construction Process. Ditching. The ditch is excavated along the pipeline centerline using

ditching machines, excavators, backhoes, and other excavation equipment. Pipelines are normally buried with a minimum of 36 in. of cover (DOT regulatory requirement). In consolidated rock, the minimum cover varies between 18 and 24 in. The cover for Class 1 locations is 18 in.; the cover for Classes 2 to 4 (railroads, highways, and public roads) is 24 in.


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Typical details for pipeline burial


Construcción

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Typical details for minimum clearance between multiple pipeline crossings


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59

Welding. The pipe strung along the ROW is welded in a progressive

manner. Sidebooms will work along the ROW lifting the pipe while a crew aligns the pipe in preparation for the "stringer bead" weld. Generally, a welder or welders (depending upon the size of the pipe) will work with the alignment crew, align the pipe, and apply the initial weld "bead." A group of welders will follow immediately behind the stringer welder(s) and apply the "hot pass" bead or seal weld. Additional welders will follow to apply the final passes of weld material.


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60

Field Joint and Anticorrosion Coating and Inspection. When the welding is completed, field joint crews clean

the weld areas and the short, adjacent bare steel on either side of the weld, and apply the field joint coating. Any nondestructive testing of the welds, such as X -ray, will be completed before application of the field joint coating. Following the completion of the field joint coating, the pipe is inspected with "holiday" detection equipment (low-voltage DC equipment that shows where the pipe coating and field joints have failures or breaches), and anomalies and breaches in the coating are repaired.


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Pipe Lowering. Upon completion of the field joint application and

coating inspection, the pipe is lowered and placed into the ditch by sidebooms or other lowering equipment.

Backfill, Cleanup, and Restoration. Following completion of the pipe lowering, the ditch is

backfilled, and the ROW is cleaned and dressed. The ROW is finely dressed, grass and vegetation replanted, and any special remediation measures or cleanup requirements are completed.


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Highway, Road, Railroad, and River Crossings. Highway, road crossings are seldom installed using

conventional, open trench methods. Typically, these crossings are installed using a wet bore or dry bore method. The boring is done by rigs that are similar to very small drilling rigs, laid horizontally, and placed in pre-excavated boring level "pits." The boring rig drills underneath the crossing area, and the pipe or casing is installed. The wet method uses a boring rig and circulates water or drilling fluid through a drill stem to open a small pilot hole, then pulls a pipe or casing-sized cutting head back to the rig, cutting a hole large enough to place the pipe or casing. The dry bore method is similar, but the casing or carrier pipe is fitted with a cutting head and is used to drill the hole and is left in place when the drill is completed. The hole is drilled dry and does not use any water or fluid to assist the drilling operation. Railroad crossings are never open cut and are always bored. Typically, railroads require that the borings be made with the dry bore method.


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Typical cased railroad-crossing ROW


Construcción

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Typical cased highway/road-crossing ROW


Construcción

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Typical details for casing seal, insulator, and vent piping.


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Typical uncased highway/road-crossing ROW


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River crossings are now typically installed using the HDD method. Open-cut trenching of rivers may be allowed by the U.S. Corps of Engineers, but HDD installations have become more economical. The HDD method uses a computer-controlled rig that controls a directional wet-bore pilot drill that can be accurately steered from the rig. The directional drill can bore a pilot hole up to a mile or more and ream a hole back to the rig large enough to install the carrier pipe. The "drill" string or pull section of pipe is welded together on the drill exit side, pretested, then pulled back to the rig side following the backreamer.


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Typical uncased small-stream-, canal-, or ditch-crossing


Construcción

69

Various types of density anchors and conventional anchor

Typical set-on reinforced-concrete pipeline weights


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The HDD method may be used to install long highway and road crossings, such as interstate highways and freeways. The wet- and dry-bore methods are limited to several hundred feet in length, which requires multiple borings to cross the distances typically required to cross interstate highways and freeways.


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Tie-ins. A crew, or crews, is typically deployed that makes all

pipeline tie-ins along the construction corridor. The tie-in crew makes the final welds at junctures where the progressive welding cannot make the final welds. Tie-ins are made at locations such as highway, road, railroad, and river and creek crossings and at drag sections, etc. The tie-in crew typically has excavation and pipe handling equipment and dedicated welders.


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Construction Details. Figures illustrate typical construction details. The

Occupational Safety and Health Admin. (OSHA) is an agency under the DOT and provides additional federal rules and regulations concerning the design, construction, and testing of pipelines. [44][45]

• 44· · OSHA Title 29 Part 1910 CFR, Occupational Safety and Health Standards for General Industry 1981. Washington, DC: US Dept. of Transportation, US Govt. Printing Office. • 45· · OSHA 2207 Part 1926 CFR, Appendices A-F, Construction Standards Concerning Excavations, Sub-Parts 1926.650, 1926.651, and 1926.652. 1981. Washington, DC: US Dept. of

Transportation, US Govt. Printing Office, Washington, DC.


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Typical details for pipeline coating in transition area


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Typical natural-gas pipeline warning sign


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Typical pipeline spread


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Flexible pipeline


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Pipeline Pigging Pipeline pigs are devices that are placed inside the pipe

and traverse the pipeline. Pigs may be used in hydrostatic testing and pipeline drying, internal cleaning, internal coating, liquid management, batching, and inspection.

Types of pigs.

1.- Introducción 2.- Sistemas de Cañerías 3.- Consideraciones de Diseño 4.- Construcciòn 5.- PIGs 6.- Slug Catchers 7.- Testing 8.- I&C

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Pipeline Pigging


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Pipeline Pigging


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Typical output from CFD


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Pig Selection Pig runs of between 50 to 100 miles are normal, but pig

runs exceeding 200 miles should be avoided as the pig may wear and get stuck in the line. Cleaning pigs may be constructed of steel body with polyurethane cups or discs and foam pigs with polyurethane wrapping, solid urethane disc, and steel body with metallic brushes. Drying pigs are usually low-density foam or multicup urethane. The intelligent pigs may be magnetic flux leakage, ultrasonic, elastic/shear wave, transponder/transducer, or combinations thereof. Internal-coating pigs are generally multicup urethane type. Batching pigs are typically bidirectional, multidisk rubber, which maintain efficiency up to 50 miles. Pigs used for obstruction inspection are typically urethane, multicup type fitted with an aluminum gauge plate or a gel type.


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Pig Selection Spheres are generally sized to be approximately 2%

greater diameter than the pipe internal diameter. Cups and discs are typically sized to be 1/16 to 1/8 in. larger in diameter than the pipe ID. Foam pigs have to be significantly oversized. Foam pigs 1 to 6 in. in diameter should be oversized by 1/4 in.; foam pigs 8 to 16 in. in diameter should be oversized 3/8 to 1/2 in.; foam pigs 18 to 24 in. in diameter should be oversized 1/2 to 1 in.; and foam pigs 28 to 48 in. in diameter should be oversized 1 to 2 in.


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Pigs are used during hydrostatic testing operations to allow the pipeline to be filled with water, or other test medium, without entrapping air. The pig is inserted ahead of the fill point, and water is pumped behind the pig to keep the pipe full of water and force air out ahead of the pig. Pigs are then used to remove the test waters and to dry the pipeline.

Operations may conduct pigging on a regular basis to

clean solids, scale, wax buildup (paraffin), and other debris from the pipe wall to keep the pipeline flow efficiency high. In addition to general cleaning, natural-gas pipelines use pigs to manage liquid accumulation and keep the pipe free of liquids. Water and natural-gas liquids can condense out of the gas stream as it cools and contacts the pipe wall and pocket in low places, which affects flow efficiency and can lead to enhanced corrosion.


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Pigs are used in product pipelines to physically separate, or "batch," the variety of hydrocarbons that are transported through the line. Product pipelines may simultaneously transport gasoline, diesel fuel, fuel oils, and other products, which are kept separated by batching pigs.

Crude-oil pipelines are sometimes pigged to keep water and solids from accumulating in low spots and creating corrosion cells. This can be especially necessary when flow velocities are less than 3 ft/sec. Multiphase pipelines may have to be pigged frequently to limit liquid holdup and minimize the slug volumes of liquid which can be generated by the system.

Pigs may be used to apply internal pipe coatings, such as epoxy coating materials, in operating pipelines. Pigs may also be used with corrosion inhibitors to distribute and coat the entire internal wetted perimeter.


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Pigs are being used more frequently as inspection tools.

Gauging or sizing pigs are typically run following the completion of new construction or line repair to determine if there are any internal obstructions, bends, or buckles in the pipe. Pigs can also be equipped with cameras to allow viewing of the pipe internals. Electronic intelligent, or smart, "pigs" that use magnetic and ultrasonic systems have been developed and refined that locate and measure internal and external corrosion pitting, dents, buckles, and any other anomalies in the pipe wall.

The accuracy of location and measurement of anomalies by the intelligent pigs has continued to improve. Initially, the electronics and power systems were so large that intelligent pigs could be used only in lines 30 in. and greater in size. The continued sophistication and miniaturization of the electronic systems used in the intelligent pigs has allowed the development of smaller pigs that can be used in small-diameter pipelines. Newly enacted DOT pipeline-integrity regulations and rules acknowledge the effectiveness of the intelligent pigs and incorporate their use in the pipeline-integrity testing process.


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Pig Launchers and Receivers Pigging facilities and considerations should be

incorporated into the pipeline system design. Basic pigging facilities require a device to launch the pig into the pipeline and a receiver system to retrieve the pig as shown. The launcher barrel is typically made from a short segment of pipe that is one to two sizes larger than the main pipeline and is fitted with a transition fitting (eccentric reducer) and a special closure fitting on the end. The barrel is isolated from the pipeline with full-port gate or ball valves. A "kicker" line, a minimum of 25% capacity of the main line, is tied from the main pipeline to the barrel, approximately 1 1/2 to 2 pig lengths upstream of the transition reducer, to provide the fluid flow to "launch" the pig into the pipeline. The barrel is fitted with blowdown valves, vent valves, and pressure gauges on the top and drain valves on the bottom. The length of the barrel is determined by the length and number of pigs to be launched at any one time. Receivers have many of the same features.


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Pig Launchers and Receivers A typical hinge-type closure for pig launching and

receiving traps consists of a forged hub, a hinged blanking head, split-yoke clamps, operating bolts, and a self-energizing O-ring gasket. Materials of construction are in accordance with ASTM specifications and manufacture complies with applicable rules of the ANSI code for pressure piping and with the ASME boiler and pressure vessel code. Most important is the pressure warning safety device with yoke positioning plate. This safety device provides visual and mechanical assurance that the yokes are in the correct position over the head for commencement of operations. Additionally, the devices serve the purpose of alerting the operator to any residual pressure in the pig launcher or receiver trap should he inadvertently attempt to open the closure before all pressure has been relieved. A pressure warning device is located at each of the yoke splits with one of the positioning lugs attached to each yoke half. Tightening the holding screw on the nipple provides a seal and locks the hinged positioning plate on the positioning lugs.


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Pig Launchers and Receivers A typical hinge-type closure for pig launching and

receiving traps consists of a forged hub, a hinged blanking head, split-yoke clamps, operating bolts, and a self-energizing O-ring gasket. Materials of construction are in accordance with ASTM specifications and manufacture complies with applicable rules of the ANSI code for pressure piping and with the ASME boiler and pressure vessel code. Most important is the pressure warning safety device with yoke positioning plate. This safety device provides visual and mechanical assurance that the yokes are in the correct position over the head for commencement of operations. Additionally, the devices serve the purpose of alerting the operator to any residual pressure in the pig launcher or receiver trap should he inadvertently attempt to open the closure before all pressure has been relieved. A pressure warning device is located at each of the yoke splits with one of the positioning lugs attached to each yoke half. Tightening the holding screw on the nipple provides a seal and locks the hinged positioning plate on the positioning lugs.


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Pig Launchers and Receivers Loosening the holding screw breaks the seal and provides

a means by which the operator can determine whether the pig launcher or receiver trap has been completely relieved of internal pressure. Continued loosening of the hold screw will allow disengagement of the positioning plate from the positioning lugs, permitting the yoke halves to be spread and the closure to be opened. There are several manufacturers of end closures, but most often Tube Turns or Modco closures are used worldwide.


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Pig Launchers and Receivers Elbows and pipe bends installed in the pipeline should

have a minimum radius of three times the main-line pipe diameter—3D bends. Intelligent pigs may require greater radius to diameter elbows and bends because of the longer length of the pigs. Tees installed in the pipeline with an outlet size 75% of the main-line ID should be equipped with bars across the tee outlet to prevent the pigs from attempting to turn into the tee and lodging in the line. Hot taps greater than 6-in. diameter added to the pipeline should be barred. If possible, tees should not be installed adjacent to one another. Check valves should be full open, and the pigs or spheres should be sized such that the pig or sphere is larger than the "bowl" cavity of the check valve.


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Typical sphere launcher and receiver traps


PIGs

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Schematic for typical horizontal trap


PIGs

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Typical sphere launcher and receiver traps


PIGs

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Schematic for pig trap facilities


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Code break for pig traps


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Recommended dimensions


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Recommended dimensions


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Slug Catchers The receiving end of the pipeline should have surge

containment to accommodate the slugs of liquid carried by the pigs. For liquid lines, additional storage capacity (tankage) will provide surge containment. Gas and multiphase lines need specially designed "slug" catcher systems to handle the intermittent liquid slugs generated by the pigging activities. When a normal gas flow is pushing the pig through a gas pipeline, the velocity can be quite large and the flow rate of liquids being pushed ahead is given by

....................(9.38) where

• QL = liquid-flow rate in front of the pig, B/D, • Qg = gas-flow rate behind the pig, MMscf/D, • T = temperature, °R, • P = line pressure, psia, • and • Z = compressibility factor, dimensionless.


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http://petrowiki.org/File:Vol3_page_386_eq_001.PNG

Slug Catchers In most systems, the instantaneous liquid-flow rate and

"energy" surge ahead of the pig will exceed the processing design capacity and capability of the receiving facility. The slug catcher provides excess storage capacity within the receiving facility and helps dissipate the excess energy generated by the high-velocity liquid slug. The basic slug catcher is essentially a liquid-separation system where the incoming liquid enters a larger-diameter pipe or a vessel, which provides additional volume for the liquid surge and provides for separation of the vapor from the liquid stream. The additional volume provided by the slug catcher reduces the stream velocity and dissipates the excess energy produced by the liquid slug.


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Slug Catchers Another typical slug-catcher design employs an inline

liquid header system attached to a series of horizontal liquid accumulators which may be several hundred feet in length. The liquid-slug stream enters the header and disperses into the accumulators, while the gas continues through the system and exits at the vapor-outlet collection header. The slug catcher may incorporate vortex breakers or other impingement devices to slow the liquid and mist extractors at the vapor outlet to capture entrained liquids. The liquid is transferred from the accumulators to the facility processing or storage.


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Slug Catchers The volume of the slug catcher is expressed as

....................(9.39) where

(Vol)SC = volume of slug catcher, bbl, Vol = volume of liquid holdup, bbl, and Qd = design liquid dump rate from the slug catcher, B/D. ....................(9.40)

where

TR = time during which slug is processed, in days.

The volume of the slug catcher should be designed with a minimum 25% safety factor.


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Typical slug catcher for two-phase flow-front elevation

1.- Introducción 2.- Sistemas de Cañerías 3.- Consideraciones de Diseño 4.- Construcciòn 5.- PIGs 6.- Slug Catchers 7.- Components 8.- Fabrication 9.- Testing


103

Typical slug catcher for two-phase flow-front elevation



104

Typical flows for slug catcher



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Typical slug catcher


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Testing Each pipeline system must be tested and inspected to

ensure that the system can be operated safely. DOT regulations specify testing and inspection requirements as well as ANSI/ASME Standard B31.3, B31.4, and B31.8 and API Standard 1104, [43] 571, [46] and 574. [47]


Testing

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Hydrostatic Testing The DOT regulations, Part 192, Subpart J, paragraph

192.501 to 192.517; Part 193, Subpart D, paragraph 193.2319 and 193.2323; and Part 195, Subpart E prescribe the pressure-testing and strength-testing requirements for natural-gas, LNG, and hazardous-liquids pipelines, respectively. The ANSI/ASME and API standards also prescribe testing requirements. Pneumatic testing is allowed for certain low-pressure pipeline systems, but the majority of pipelines are tested with water.


Testing

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Hydrostatic Testing To conducting the hydrostatic testing, a profile of the test

section should be developed showing the maximum and minimum elevations, the maximum allowable working pressure (MAWP) determined at the lowest elevation point, the location of the fill and pressure pump, minimum pressure required at the pressure pump determined by the maximum pressure at the lowest elevation, and water-source quality and discharge/disposal point. The profile of the test segment provides a graphical representation of the test segment, which helps the testing engineer determine the location of air bleed vents and the fill rate and pig velocity required to prevent air entrapment, and verify that the test will not overpressure or underpressure the pipe in the segment. The elevation differential can become a major consideration. When radical changes in elevation occur over short distances, it may be necessary to subdivide the original segment into shorter test segments.


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Hydrostatic Testing Each 100 ft of elevation difference represents

approximately 43.3 psi of pressure differential, which can result in high points being underpressured and low points being overpressured during the test. The test profile is also used to document the location of the fill pump, the test pump, the dead-weight gauge, and the pressure/temperature recording equipment.


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Hydrostatic Testing The typical testing equipment that is needed to conduct

the hydrostatic test is a temporary fill manifold complete with valves (pressure rated at a minimum of 1.5 times the maximum test pressure), dewatering manifold complete with valves (also pressure rated at a minimum of 1.5 times the maximum test pressure), foam or urethane pigs, low-pressure/high-volume fill pump with filtration equipment, high-pressure positive-displacement pump, certified dead-weight gauge(s), chart-type pressure recorder, chart-type temperature recorder for the water, chart-type temperature recorder for ambient air, pressure gauges rated at 50 to 75% of the maximum test pressure, compressed air or nitrogen source for dewatering, and discharge water filtration equipment. Temporary water-storage or holding tanks may be needed to supply reserve test water or serve as holding or settlement devices for dewatering.


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Nondestructive Testing. Nondestructive testing and inspection of the welds is

required by the DOT regulations Part 192, Subpart E, paragraph 192.243[22] for natural-gas pipelines; Part 193, Subpart D, paragraph 193.2321[23] for LNG lines; and Part 195, Subpart D, paragraph 195.234[25] for hazardous-liquid lines. ANSI/ASME Standards B31.3, [7] B31.4, [8] and B31.8[9] also prescribe nondestructive requirements.

Inspection. Each of the regulations and industry codes requires visual

inspection of welds and construction process.


Testing

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Pipeline integrity testing-elevation vs. station number


Testing

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Planificacion de Prueba


Testing

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Temperature isotherms for buried pipeline on summer


Testing

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Temperature isotherms for buried pipeline on winter


Testing

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Instrumentation and Control

Compressor stations, pump stations, and related facilities may require emergency isolation equipment to protect the pipeline. Emergency-shutdown (ESD) systems consist of automatic shutoff isolation valves located at the main inlet and outlet to the stations/facilities and coordinated pressure-relief systems between the isolation valves. The ESD system protects both the pipeline and facility by stopping the flow into and out of the facility and limits the feed source in the event of fire, explosion, or other emergency.

Basic pipeline instrumentation includes strategically located pressure gauges and pressure-monitoring instruments, temperature gauges and monitoring instruments, and pressure control/limitation and relief equipment.


I&C

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Types of compressors


I&C

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Compressor coverage chart


I&C

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Station piping schematic


I&C

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Classification of Pumps


I&C

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Specific speed and performance


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Instrumentation and Control

Pipeline control systems may consist of simple devices such as automatic pressure-control valves to the sophisticated total supervisory-control-and-data acquisition (SCADA) control system. The SCADA system can monitor and control, on a real-time basis, an entire pipeline system. The SCADA system can open and close valves, start and stop pumps/compressors, monitor and control flow, sample the product, monitor and regulate pressures and temperatures, and perform many other functions. SCADA systems are typically neither needed nor practical for small, gathering pipeline systems.


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SSDH 0433/2007. 20070426


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SSDH 0433/2007. 20070426


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SSDH 0433/2007. 20070426


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Centro Nacional de Medición y Control de Hidrocarburo.

17 Mayo 2005 - Ley de Hidrocarburos N° 3058, articulo 18 • YPFB constituirá, organizara, instalara y operara el Centro

Nacional de Medición y Control de Hidrocarburos. 27 Junio 2005 - Decreto Supremo Nº 28224, art. 4 • Creación del CNMCH y asignación de recursos del

Ministerio de Hacienda. 26 Octubre 2007 - Resolución del Directorio Nº 51/2007 • Dependencia: Vicepresidencia de Administración,

Contratos y Fiscalización - VPACF 27 Junio 2011- Resolución del Directorio Nº 50/2011 • El CNMCH es declarado el ENTEL OFICIAL DE LA

MEDICION DE HIDROCABUROS para YPFB en Bolivia.


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Transporte & Distribución (Pipeline)

• Bibliografía Básica – Pipeline Design and Construction - M Mohitpour

• Bibliografía Complementaria – GULF-S PAPAVINASAM-Corrosion Control in O&G – PPSA-An Introduction to Pipeline Pigging – C SZWED - Selección de la Estrategia para Diseñar Slug

Catcher – NTNU T Karam - Slug Catchers in Natural Gas Production – G Petrie - Airborne Topographic Laser Scanners – DS 24335 RASH 19960719 – SSDH 0433/2007. 20070426

03 t_d

Engineering

Transcript of 03 t_d