Wells – Processes – Placing or shifting well part
Patent
1996-03-19
1997-06-17
Neuder, William P.
Wells
Processes
Placing or shifting well part
166 772, E21B 1908
Patent
active
056389043
DESCRIPTION:
BRIEF SUMMARY
FIELD OF INVENTION
This invention pertains to safeguarded methods and apparatus for providing fluid communication with coiled tubing, useful in communicating fluids within wells, and particularly applicable to drill stem testing and/or operations in sour wells. This invention also pertains to multicentric coiled-in-coiled tubing, useful for safeguarded downhole or conduit operations, and its method of assembly.
BACKGROUND OF INVENTION
The oil and gas industry uses various methods to test the productivity of wells prior to completing and tying a well into a pipeline or battery. After drilling operations have been completed and a well has been drilled to total depth ("TD"), or prior to reaching TD in the case of multi-zoned discoveries, it is common to perform a drill stem test ("DST"). This test estimates future production of oil or gas and can justify a further expenditure of capital to complete the well.
The decision to "case" a well to a particular depth, known as a "casing point election", can result in an expenditure in excess of $300,000. Without a DST, a wellsite geologist must make a casing point election based on only core samples, cuttings, well logs, or other indicators of pay thicknesses. In many cases reservoir factors that were not knowable at the time of first penetration of the producing zone, and thus not reflected in the samples, cuttings, etc., can control the ultimate production of a well. A wellsite geologist's problem is exacerbated if the well is exploratory, or a wildcat well, without the benefit of comparative adjacent well information. Further, the geologist must make a casing point election quickly as rig time is charged by the hour.
A DST comprises, thus, a valuable and commonly used method for determining the productivity of a well so that optimal information is available to the geologist to make a casing point election. Traditionally the DST process involves flowing a well through a length of drill pipe reinserted through the static drilling fluid. The bottom of the pipe will attach to a tool or device with openings through which well fluids can enter. This perforated section is placed across an anticipated producing formation and sealed off from the rest of the wellbore with packers, frequently a pair of packers placed both above and below the formation. The packer placement or packing off technique permits an operator to test only an isolated section or cumulative sections. The testing can involve actual production into surface containers or containment of the production fluid in the closed chamber comprised by the pipe, pressure testing, physically retrieving samples of well fluids from the formation level and/or other valuable measurements.
The native pressure in producing reservoirs is controlled during drilling through the use of a carefully weighted fluid, referred to above and commonly called "drilling mud". The "mud" is continuously circulated during the drilling to remove cuttings and to control the well should a pressurized zone be encountered. The mud is usually circulated down the inside of the drill pipe and up the annulus outside of the pipe and is typically made up using water or oil based liquid. The mud density is controlled through the use of various materials for the purpose of maintaining a desired hydrostatic pressure, usually in excess of the anticipated native reservoir pressure. Polymers and such are typically added to the mud to intentionally create a "filter cake" sheath-like barrier along the wellbore surface in order to staunch loss of over-pressured drilling fluid out into the formation.
As can be easily appreciated, when an upper packer of a DST tool seals an annular area between a test string and a borehole wall, the hydrostatic pressure from the column of drilling fluid is relieved on the wellbore below the packer. The well below the packer, thus, can flow if an open fluid communication channel exists to the surface. At least the well will flow to the extent that native pressure present at the open formation of the isolated section exceeds t
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Misselbrook John G.
Sask David E.
Neuder William P.
Nowsco Well Service Ltd.
Shaper Sue Z.
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