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Search Petrowiki: 1.10.2 Directional Drilling Systems AND Equipment
...Category:1.10.2 Directional drilling systems and ...equipment . Pages in category "...1.10.2 Directional drilling systems and ...
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...Taxonomy Contents * 1 Drilling * 2 Completions * 3 Production and operations * 4 Projects, facilities, and construction * 5 Re...afety, environment, and sustainability * 7 Management * 8 Data science and engineering analytics Drilling 1 ...Drilling 1.1 Well planning 1.1.1 Well site preparation 1.1.2 Authority for expenditures (AFE) 1.1.3 Tr...
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...tly 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...mation on workovers with coiled tubing, review the chapter on workover design and procedures in the Drilling Engineering section of thisHandbook. Process of Manufacture Tubing made to API specifications us...
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. When selecting the material, environmental conditions, the projected corrosivity of the well fluids, the minimum and maximum pressures and temperature, safety aspects, and cost-effectiveness must be considered. The tubing must be designed to meet all stresses and conditions that occur during routine operation of the well and should have an adequate margin for unusual load conditions. It must withstand the stresses caused by tension, burst, and collapse, and it must resist the corrosive action of well fluids throughout the well life. In addition, the tubing must be handled and installed so that the tubing produces the well without failure or without causing undue operating problems. The American Petroleum Institute (API) developed Specifications, Recommended Practices, and Bulletins for steel tubing that meet the major needs of the oil and gas industry.[1][2][3][4][5][6][7][8][9][10][11][12][13]API This effort continues, and many of these documents (with modifications) have become International Organization for Standardization (ISO) documents.
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...ducing "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 pro...duction, treating, storage, and measurement equipment are located in various chapters of thisHandbook. * Fig. 9.1--Wellhead to sales (courtesy of AME...
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 thisHandbook. 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.
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...ication Information Petroleum Engineering Handbook Larry W. Lake, Editor-in-Chief Volume II - Drilling Engineering Robert F. Mitchell, Editor Copyright 2006, Society of Petroleum Engineers Chapter...preventing blowouts by quickly forming a seal, (3) protecting the casing from shock loads in deeper drilling, and (4) sealing off zones of lost circulation or thief zones. Remedial cementing is usually done ... approach to remedial cementing is to avoid it by thoroughly planning, designing, and executing all drilling, primary cementing, and completion operations. The need for remedial cementing to restore a well ' ...
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. A cement slurry is prepared and pumped down a wellbore to the problem area or squeeze target. The area is isolated, and pressure is applied from the surface to effectively force the slurry into all voids. The slurry is designed specifically to fill the type of void in the wellbore, whether it is a small crack or micro-annuli, casing split or large vug, formation rock or another kind of cavity. Thus, the slurry design and rate of dehydration or fluid loss designed into the slurry is critical, and a poor design may not provide a complete fill and seal of the voids.
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