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API St 65-2-2010 pdf free download

API St 65-2-2010 pdf free download.Isolating Potential Flow Zones During Well Construction.
API Specification 10D-2/ISO 10427-2, Recommended Practice for Centralizer Placement and Stop Collar Testing API Recommended Practice 10F/ISO 10427-3, Recommended Practice for Performance Testing of Cementing Float Equipment API Technical Report 10TR1, Cement Sheath Evaluation API Technical Report 10TR3, Temperatures for API Cement Operating Thickening Time Tests API Technical Report 10TR4, Technical Report on Considerations Regarding Selection of Centralizers for Primary Cementing Operations API Technical Report 10TR5, Technical Report on Methods for Testing of Solid and Rigid Centralizers API Recommended Practice 13B-1/ISO 10414-1, Recommended Practice for Field Testing Water-Based Drilling Fluids API Recommended Practice 13B-2/ISO 10414-2, Recommended Practice for Field Testing Oil-based Drilling Fluids API Recommended Practice 53, Blowout Prevention Equipment Systems for Drilling Operations API Recommended Practice 65, Cementing Shallow Water Flow Zones in Deep Water Wells API Recommended Practice 90, Annular Casing Pressure Management for Offshore Wells 3 Definitions, and Abbreviated Terms 3.1 Definitions For the purposes of this document the following terms and definitions apply. In addition to those listed below other definitions and abbreviations may be found in oilfield glossaries at websites listed in the Bibliography. [47,48,49,50,51] 3.1.1 ambient pressure Pressure external to the wellhead. In the case of a surface wellhead it would be 0 psig. In the case of a subsea well head, it would be equal to the hydrostatic pressure of seawater at the depth of the subsea wellhead in psig. 3.1.2 annular flow The flow of formation fluids (liquids and/or gases) from the formation into a space or pathway in an annulus within a well. The annular flow may follow various flow paths inside the annulus to other points including those at shallower or deeper depths. 3.1.4 annular pressure buildup APB Pressure generated within a sealed annulus by thermal expansion of trapped wellbore fluids typically during production. May also occur during drilling operations when trapped annular fluids at cool shallow depths are exposed to high temperatures from fluids circulating in deep, hot hole sections. This thermally induced pressure is defined and listed in API RP 90 as thermal casing pressure. APB is also referred to as annular fluid expansion (AFE). 3.1.5 annuli Plural of annulus. A well may contain several annuli formed by multiple casing and liner pipe strings. 3.1.6 annulus The space between the borehole and tubulars or between tubulars, where fluid can flow. The annulus designation between the production tubing and production casing is the “A” annulus. Outer annuli between other strings are designated B, C, D, etc. as the pipe sizes increase in diameter. 3.1.7 barrier (barrier element) A component or practice that contributes to the total system reliability by preventing liquid or gas flow if properly installed. 3.1.8 blowout preventer BOP A device attached to the casing head that allows the well to be sealed to confine the well fluids in the wellbore. Refer to API RP 53 or other relevant standards for further information. 3.1.9 borehole Wellbore sections which are not cased with pipe, commonly called open hole. 3.1.10 bottom hole assembly BHA Bottom hole assembly is the collection of the bit, drill collars, stabilizers, reamers, hole openers, MWD/LWD/PWD, mud motor, directional steering system and other tools at the base of the drill string that serve special purposes associated with drilling. 3.1.11 cased hole The wellbore intervals in a well that are cased with casing and/or liner pipe. The diameter of these hole sections is the inside diameter of the pipe contained therein.
3.1.13 conductor casing Provides structural support for the well, wellhead and completion equipment, and often provides hole stability for initial drilling operations. This casing string is typically not designed for pressure containment. However, in some cases, the conductor casing may serve to isolate shallow formations, similar to a surface casing. 3.1.14 critical gel strength period CGSP The time between the development of the critical static gel strength (CSGS) and a static gel strength of 500 lbf/100 ft 2 . 3.1.15 critical static gel strength CSGS The static gel strength of the cement that results in the decay of hydrostatic pressure to the point at which pressure is balanced (hydrostatic equals pore pressure) at a point adjacent to the potential flowing formation(s). 3.1.16 diverter A device connected to the top of the wellhead or marine riser, directing flow away from the rig.

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