دیکشنری تخصصی مهندسی نفت - نسخه آنلاین

n: 1. the pressure at the bottom of a borehole. It is caused by the hydrostatic pressure of the wellbore fluid and, sometimes, by any back-pressure held at the surface, as when the well is shut in with blowout preventers. When mud is being circulated, bottomhole pressure is the hydrostatic pressure plus the remaining circulating pressure required to move the mud up the annulus. 2. the pressure in a well at a point opposite the producing formation, as recorded by a bottomhole pressure bomb.

n: The pressure at the bottom of the borehole, or at a point opposite the production formation.

n: a test that measures the reservoir pressure of the well, obtained at a specific depth or at the midpoint of the producing zone. A flowing bottomhole pressure test measures pressure while the well continues to flow;a shut-in bottomhole pressure test measures pressure after the well has been shut in for a specified period of time. See bottomhole pressure. bottomhole pressure gauge.

v:.1. to shut in a well temporarily that is capable of producing oil or gas. 2. to close the blowout preventers on a well to control a kick. The blowout preventers close off the annulus so that pressure from below cannot flow to the surface.

v: (1) Close the production well temporarily. (2) Close the BOP to prevent blowout.

to shut-in a well.

n: a device used to direct fluids flowing from a well away from the drilling rig. When a kick is encountered at shallow depths, the well often cannot be shut in safely;therefore, a diverter is used to allow the well to flow through a side outlet (a divetter line).

n: refer to diverter

abbr: emergency shut down, an automated platform system to shut in an SCSSV and/or SSV.

emergency shut-down.

n: the force exerted by fluids in a formation, recorded in the hole at the level of the formation with the well shut in. Also called reservoir pressure or shut-in bottomhole pressure.

n: the pressure exerted by the formation fluids at a particular point in the formation,sometimes called reservoir pressure or pore pressure.

the pressure of the fluid in the formation. The initial reservoir pressure is the pressure at discovery.

n: in a well-control operation, closing the BOP without first opening an alternate flow path up the choke line. When the BOP is closed, pressure in the annulus cannot be read on the casing pressure gauge.

n: a short-time backpressure test for low-permeability reservoirs that otherwise require excessively long times for pressure stabilisation when wells are shut in.

a multi-rate drawdown and build-up test with different drawdowns of the same duration but buildups reaching stabilization.

n: the length ratio of fluid in the holebore after discovery overflow and shut in.

n: the amount of pressure that the casing seat can take without fracturing. It is calculated from the height and volume of the kick in the well.

n: after overflow and shut in, the maximum difference the fluid density in the hole from the equivalent density that converted by casing allowable pressure and volume pressure in the holebore unless it happens overflow.