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. Some companies use the more stringent ANSI/ASME Standard B31.3 for onshore facilities. In other countries, similar standards apply with minor variations.
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. Figure 1 shows several types of pipeline pigs. 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.
Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. An outer steel shell that connects a drill ship, jackup or floater to the well template on the ocean floor. The drill string is run through the riser and the returning mud and cutting flow u the drill pipe / riser annulus.
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 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: 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.