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...The considerations and standards guiding pipeline design insures stability and integrity in the industry. The fluid flow equations and formulas presented t...hus far enable the engineer to initiate the design of a piping or pipeline system, where the pressure drop available governs the selection of pipe siz...ere are no codes or standards that specifically apply to the oil and gas production facilities, the design engineer may select one of the industry codes or standards as the basis of ...
The considerations and standards guiding pipeline design insures stability and integrity in the industry. The fluid flow equations and formulas presented thus far enable the engineer to initiate the design of a piping or pipeline system, where the pressure drop available governs the selection of pipe size. This is discussed below in the section on velocity considerations for pipelines. Once the inner diameter (ID) of the piping segment has been determined, the pipe wall thickness must be calculated. If there are no codes or standards that specifically apply to the oil and gas production facilities, the design engineer may select one of the industry codes or standards as the basis of design. The design and operation of gathering, transmission, and distribution pipeline systems are usually governed by codes, standards, and regulations. The design engineer must verify whether the particular country in which the project is located has regulations, codes, and standards that apply to facilities and/or pipelines. In the U.S, piping on offshore facilities is mandated by regulation to be done in accordance with ANSI/ASME Standard B31.3. Most onshore facilities are designed in accordance with ANSI/ASME Standard B31.4 or B31.8, depending on whether it is an oil or gas facility. Some companies use the more stringent ANSI/ASME Standard B31.3 for onshore facilities.
...e Dunn Clegg, Editor Copyright 2006, Society of Petroleum Engineers Chapter 3 – Tubing Selection, Design, and Installation Joe Dunn Clegg, Consultant and Erich F. Klementich, Consultant ISBN 978-1-55563... of 2 3/8 to 4 1/2 in. but may be as large as 20 in. or as small as 1.050 in. The proper selection, design, and installation of tubing string are critical parts of any well completion. See the chapter on in...delines on its use. For information on workovers with coiled tubing, review the chapter on workover design and procedures in the Drilling Engineering section of this Handbook. Tubing made to API specificat...
Introduction Tubing is the normal flow conduit used to transport produced fluids to the surface or fluids to the formation. Its use in wells is normally considered a good operating practice. The use of tubing permits better well control because circulating fluids can kill the well; thus, workovers are simplified and their results enhanced. Flow efficiency typically is improved with the use of tubing. Furthermore, tubing is required for most artificial lift installations. Tubing with the use of a packer allows isolation of the casing from well fluids and deters corrosion damage of the casing. Multicompletions require tubing to permit individual zone production and operation. Governmental rules and regulations often require tubing in every well. Permission may be obtained for omission of tubing in special cases (tubingless completions). These special completions typically are flowing wells with relatively small casing. Tubing strings are generally in outside diameter (OD) sizes of 2 3/8 to 4 1/2 in. The proper selection, design, and installation of tubing string are critical parts of any well completion. See the chapter on inflow and outflow in this section of the handbook for more information. Tubing strings must be sized correctly to enable the fluids to flow efficiently or to permit installation of effective artificial lift equipment. A tubing string that is too small causes large friction losses and limits production. It also may severely restrict the type and size of artificial lift equipment. A tubing string that is too large may cause heading and unstable flow, which results in loading up of the well and can complicate workovers. The planned tubing must easily fit inside the installed casing.
...timated based on drillstem tests of exploration wells or from existing wells in similar fields. The design flow rates are estimated from well logs and reservoir simulations. Even if the estimates are good, ...ures change over the life of the field as wells mature and new wells are drilled. Facilities have a design rate that is a best-guess maximum flow based on the number of wells, production profiles, and total...reservoir. The actual production rates for a facility increase as the wells are completed up to the design rate. This rate will be maintained as long as possible by drilling additional wells; then, oil and ...
Oil or gas wells produce a mixture of hydrocarbon gas, condensate, or oil; water with dissolved minerals, usually including a large amount of salt; other gases, including nitrogen, carbon dioxide (CO2), and possibly hydrogen sulfide (H2S); and solids, including sand from the reservoir, dirt, scale, and corrosion products from the tubing. For the hydrocarbons (gas or liquid) to be sold, they must be separated from the water and solids, measured, sold, and transported by pipeline, truck, rail, or ocean tanker to the user. Gas is usually restricted to pipeline transportation but can also be shipped in pressure vessels on ships, trucks, or railroad cars as compressed natural gas or converted to a liquid and sent as a liquefied natural gas (LNG). This chapter discusses the field processing required before oil and gas can be sold. The goal is to produce oil that meets the purchaser's specifications that define the maximum allowable water, salt, or other impurities. Similarly, the gas must be processed to meet purchaser's water vapor and hydrocarbon dewpoint specifications to limit condensation during transportation. The produced water must meet regulatory requirements for disposal in the ocean if the wells are offshore, reservoir requirements for injection into an underground reservoir to avoid plugging the reservoir, and technical requirements for other uses, such as feed to steam boilers in thermal-flood operations, or in special cases, for irrigation. The equipment between the wells and the pipeline, or other transportation system, is called an oilfield facility. An oilfield facility is different from a refinery or chemical plant in a number of ways.
...ransferred for eventual sale. Fig. 9.1 is a simplified diagram that illustrates the typical, basic "wellhead to sales" concept. The typical system begins at the well flow-control device on the producing "wing...(s)" of the wellhead tree and includes the well "flowline," production/treating/storage equipment, custody-transfer meas...ng, storage, and measurement equipment are located in various chapters of this Handbook. Fig. 9.1--Wellhead to sales (courtesy of AMEC Paragon). The piping and pipeline systems typically associated with pro...
Once oil and gas are located and the well is successfully drilled and completed, the product must be transported to a facility where it can be produced/treated, stored, processed, refined, or transferred for eventual sale. Figure 1.1 is a simplified diagram that illustrates the typical, basic "wellhead to sales" concept. The typical system begins at the well flow-control device on the producing "wing(s)" of the wellhead tree and includes the well "flowline," production/treating/storage equipment, custody-transfer measurement equipment, and the gathering or sales pipeline. Information and detailed discussions concerning petroleum production, treating, storage, and measurement equipment are located in various chapters of this Handbook. The piping and pipeline systems typically associated with producing wells include, but are not limited to, the well flowline, interconnecting equipment piping within the production "battery," the gathering or sales pipeline, and the transmission pipeline. A brief description of the associated piping/pipeline systems is given next. 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. 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. 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. The transmission pipeline is a "cross-country" pipeline that is specifically designed to transport petroleum products long distances.
...on that is needed to form an emulsion may result from the bottomhole pump; flow through the tubing, wellhead, manifold, or flowlines; the surface transfer pump; pressure drop through chokes, valves, or other ...of poor cementing or reservoir management can increase emulsion-treating problems, as can a process design that subjects the oil/water mixture to excess turbulence. Unnecessary turbulence can be caused by o...ould not be allowed to occur when the sample is extracted. For example, for samples obtained at the wellhead, manifold, or oil-and-gas separator, emulsification can occur because of the turbulence created whi...
Chemical treatment with demulsifiers is used to counteract the natural surfactants present, and wetting agents or other chemicals sometimes are used to carry the suspended solids into the water layer. The presence of a band of emulsion in centrifuged samples indicates that further chemical treatment might be needed.
...s, the friction pressures, the hydrostatic pressures, the temperature, and, thus, the cement slurry design. Wellbore depth also controls hole size and casing size. Extremely deep wells have their own distin...ct design challenges because of high temperatures, high pressures, and corrosive fluids. The geometry of the...eaving equal annular space around the casing. The temperatures of the wellbore are critical in the design of a cement job. There are basically three different temperatures to consider: the bottomhole circu...
Remedial cementing requires as much technical, engineering, and operational experience, as primary cementing but is often done when wellbore conditions are unknown or out of control, and when wasted rig time and escalating costs force poor decisions and high risk. Squeeze cementing is a "correction" process that is usually only necessary to correct a problem in the wellbore. Before using a squeeze application, a series of decisions must be made to determine (1) if a problem exists, (2) the magnitude of the problem, (3) if squeeze cementing will correct it, (4) the risk factors present, and (5) if economics will support it. Most squeeze applications are unnecessary because they result from poor primary-cement-job evaluations or job diagnostics. Squeeze cementing is a dehydration process.
...ence, corrosion requires the presence of water. This overall process is shown schematically in Fig. 1. The space between the anode and cathode may be small or large depending on a number of factors. F...MP35N previously used for such extreme conditions. Nickel alloys are also used as weld cladding for wellhead and valve equipment. As with scale problems, the appropriate addition of chemicals can often inhib...
Corrosion of metal in the presence of water is a common problem across many industries. The fact that most oil and gas production includes co-produced water makes corrosion a pervasive issue across the industry. Age and presence of corrosive materials such as carbon dioxide (CO2) and hydrogen sulfide (H2S) exacerbate the problem. Corrosion control in oil and gas production is reviewed in depth in Treseder and Tuttle, Brondel, et al., and NACE, from which some of the following material is abstracted. Iron is inherently (thermodynamically) sufficiently active to react spontaneously with water (corrosion), generating soluble iron ions and hydrogen gas. The utility of iron alloys depends on minimizing the corrosion rate. Corrosion of steel is an "electrochemical process," involving the transfer of electrons from iron atoms in the metal to hydrogen ions or oxygen in water. This separation of the overall corrosion process into two reactions is not an electrochemical nuance; these processes generally do take place at separate locations on the same piece of metal. This separation requires the presence of a medium to complete the electrical circuit between anode (site of iron dissolution) and cathode (site for corrodant reduction). Electrons travel in the metal phase, but the ions involved in the corrosion process cannot. Ions require the presence of water; hence, corrosion requires the presence of water.
...uence, this may be more important than capturing the areal variation in reservoir description. Case Design. Careful thought should be given to identifying cases to be run with the model to avoid running all...lan. This plan is developed with input from several engineering disciplines. The drilling engineers design drilling schedules, wellbore trajectories, and casing and cementing programs to locate wells at the... required location for the lowest effective cost. The subsurface engineers design tubulars, completion techniques, stimulation processes, and artificial lift equipment required for ...
This field produces from a structure that lies above a deep-seated salt dome (salt has been penetrated at 9,000 ft) and has moderate fault density. A large north/south trending fault divides the field into east and west areas. There is hydraulic communication across the fault. Sands were deposited in aeolian, fluvial, and deltaic environments made up primarily of a meandering, distributary flood plain. Reservoirs are moderate to well sorted; grains are fine to very fine with some interbedded shales. There are 21 mapped producing zones separated by shales within the field but in pressure communication outside the productive limits of the field. The original oil column was 400 ft thick and had an associated gas cap one-third the size of the original oil column. Porosity averages 30%, and permeability varies from 10 to 1500 md.
...asurement sections of the logging assembly as wellsite needs change is valuable, thus prompting the design of modular MWD/LWD systems. Operational issues, such as fault tolerance, power sharing, data sharin...osure of relatively large areas of inflatable packers to the wellbore environment calls for careful design and handling to avoid damage. An alternative approach to acquiring data follows the traditional wir...rovide reasonable data in a shorter time period (although from a shallower depth) than the DST-type design. Early indications are that FTWD tools will be adopted quite rapidly by the industry provided that ...