API RP 59-2006 pdf download.Recommended Practice for Well Control Operations.
1 Scope 1.1 PURPOSE The purpose of these recommended practices is to provide information that can serve as a voluntary industry guide for safe well control operations. This publication is designed to serve as a direct field aid in well control and as a technical source for teaching well control principles. This publication establishes recommended operations to retain pressure con- trol of the well under pre-kick conditions and recommended practices to be utilized during a kick. It serves as a companion to API RP 53, Recommended Practice for Blowout Preven- tion Equipment Systems for Drilling Wells and API RP 64 Recommended Practice for Diverter Systems Equipment and Operations (reader should check for the latest edition). RP 53 establishes recommended practices for the installation and testing of equipment for the anticipated well conditions and service and RP 64 establishes recommended practices for installation, testing, and operation of diverters systems and discusses the special circumstances of uncontrolled flow from shallow gas formations. 1.2 BOP INSTALLATIONS The recommended practices are separated into two main systems: 1. Blowout preventers (BOPs) at the surface within reach and sight of the driller or well service unit operator, and 2. BOPs installed on the seafloor with relatively long choke and kill lines.
1.4 FURTHERING THE UNDERSTANDING OF WELL CONTROL Details of well control technology and reasons for the rec- ommended procedures are included in Section 4, “Principles of Well Control.” Section 4 was prepared so it can be used as a technical base for instructing personnel in well control oper- ations. Appendix A contains several special pressure and pressure gradient calculations and examples to further emphasize the techniques and calculations that can aid a well control supervisor in understanding well control operations. 1.5 DEEPWATER The International Association of Drilling Contractors (IADC) has published guidelines for planning and drilling deepwater wells, IADC Deepwater Well Control Guidelines, 1998 Edition. The reader is referred to that document for more complete coverage of deepwater well control.
3.1.5 annulus friction pressure: Circulating pressure loss inherent in the annulus between the drill string and cas- ing or open hole. 3.1.6 backpressure (casing pressure, choke pres- sure): The pressure existing at the surface on the casing side of the drill string/annulus flow system. 3.1.7 barite plug: A settled volume of barite particles from a barite slurry placed in the well bore to seal off a pres- sured zone. 3.1.8 barite slurry: A mixture of barium sulfate, chemi- cals, and water of a unit density between 18 and 22 pounds per gallon (lb/gal). 3.1.9 belching: A slang term to denote flowing by heads. 3.1.10 bell nipple: A piece of pipe, with inside diameter equal to or greater than the BOP bore, connected to the top of the BOP or marine riser with a side outlet to direct the drilling fluid returns to the shale shaker or pit. Usually has a second side outlet for the fill-up line connection. 3.1.11 bleeding: Controlled release of fluids from a closed and pressured system in order to reduce the pressure.
3.1.22 bottom-hole pressure: Depending upon the context, either a pressure exerted by a column of fluid con- tained in the well bore or the formation pressure at the depth of interest. 3.1.23 broaching: Venting of fluids to the surface or to the seabed through channels external to the casing. 3.1.24 bullheading: A term to denote pumping into closed-in well without returns. 3.1.25 casing pressure: See Backpressure. 3.1.26 casing seat test: A procedure whereby the for- mation immediately below the casing shoe is subjected to a pressure equal to the pressure expected to be exerted later by a higher drilling fluid density or by the sum of a higher drill- ing fluid density and backpressure created by a kick. 3.1.27 casing shoe: A tool joint connected to the bottom of a string of casing designed to guide the casing past irregu- larities in the open hole; usually rounded at the bottom in shape and composed of drillable materials. 3.1.28 choke: A device with either a fixed or variable aperture used to control the rate of flow of liquid and/or gas. 3.1.29 choke manifold (control manifold): The sys- tem of valves, chokes, and piping to control flows from the annulus and regulate pressures in the drill string/annulus flow system. 3.1.30 choke line: The high-pressure piping between BOP outlets or wellhead outlets and the choke manifold. 3.1.31 choke pressure: See Backpressure. 3.1.32 circulating head: A device attached to the top of drill pipe or tubing to allow pumping into the well. 3.1.33 closing unit: The assembly of pumps, valves, lines, accumulators, and other items necessary to open and close the BOP equipment. 3.1.34 conductor casing or conductor pipe (onshore and bottom-supported offshore installa- tions): A relatively short string of large diameter pipe that is set to keep the top of the hole open and provide a means of returning the upward flowing drilling fluid from the well bore to the surface drilling fluid system until the first casing string is set in the well.