Wells – Processes – Placing or shifting well part
Reexamination Certificate
2002-05-01
2004-03-30
Tsay, Frank (Department: 3672)
Wells
Processes
Placing or shifting well part
C166S387000, C166S077200
Reexamination Certificate
active
06712150
ABSTRACT:
FIELD OF INVENTION
The invention relates to coiled tubing strings, and in particular to at least partial dual tubing strings, including methods for assembling such strings.
BACKGROUND OF INVENTION
This invention is tangentially related to U.S. Pat. No. 5,638,904—Safeguarded Method and Apparatus for Fluid Communication Using Coiled Tubing, With Application to Drill Stem Testing—Inventors Misselbrook et al.; PCT Application US 97/03563 filed Mar. 5, 1997 for Method and Apparatus using Coil-in-Coil Tubing for Well Formation, Treatment, Test and Measurement Operations—Inventors Misselbrook et al; and U.S. Ser. No. 08/564,357 entitled Insulated and/or Concentric Coiled Tubing.
The instant invention relates to apparatus and assembly for at least a partial dual tubing or “coil-in-coil” tubing string, sometimes referred to as PCCT, wherein an inner tubing is sealed within an outer coiled tubing. It is to be understood that although the term coil-in-coil may be used, the “inner tubing” need not necessarily be “coiled tubing”, or “coiled tubing” as it is known or practiced today. Standard “coiled tubing” as the “inner tubing” does afford a practical solution for first embodiments. The inner tubing, however, could comprise a liner, for instance. Further, there may or may not be an annulus per se defined between the inner and the outer tubing, in whole or in part. Any annulus formed is preferably narrow.
Since providing dual tubing in a string should raise the cost of a string, there may be a cost advantage to minimizing the length of the dual portion. Hence, “partial” coil-in-coil strings, or PCCT, may have cost advantages. A general purpose multi-use partial dual string should have enough dual length to cover the anticipated length of well interval to be serviced. The overall length of the PCCT string will be chosen to service a typical depth range of wells in a particular location. But, coiled tubing may be added or removed from the bottom of the outer coiled tubing string to suit wells outside of the standard depth range. A full dual tubing string, of course, would perform adequately but would be more expensive. Alternately, a partial dual string could be formed by connecting a full dual portion with a single portion. Such a partial dual string could be pre-formed and transported to a job or formed at a job site.
A key purpose for using an at least partial dual string is to provide a protective barrier at the surface to enable safe pumping of well fluids up or down. (Surface is used generally herein to refer to above the wellhead.) To provide this benefit, a dual string has a sealed annulus or the tubings are sealed together, in whole or in part. A dual tubing string annulus preferably would be sealed at or proximate a lower end of the inner tubing, and the seal is preferably located across the annulus between the inner and outer coiled tubing, most preferably within the outer coiled tubing. Preferably also, any annulus would be narrow, to maximize working space. Means can be provided to monitor fluid status, such as fluid flow or pressure, within any annulus formed. A pressurized fluid such as nitrogen could be injected, for instance, into the annulus, or existing fluid within an annulus could be pressured up.
Coiled tubing is commonly utilized in well servicing for working over wells. In a workover, a continuous coiled tubing string is injected into a live well using an associated stuffing box located over the wellhead. Many coiled tubing workovers take place under live well conditions. Coiled tubing has proven particularly useful when working through production tubing or completion tubing.
In normal operations coiled tubing is over-pressured vis a vis well pressure. This insures that were any leaks to develop in the tubing, they would result in flow out of the tubing rather than the reverse, which is important for safety reasons. Pressure in the coiled tubing also keeps well fluids from backing up the tubing bore. Well fluids are relegated to the annular space between the coiled tubing and the production tubing or completion tubing. If produced up the annular space outside the coiled tubing, well fluids can be handled in the usual safe manner at a wellhead.
Fluids pumped down through a coiled tubing string typically enter the tubing at a valve located upon an axle of the reel carrying the string. The fluids run through the remaining tubing wound around the reel, over the gooseneck, down the injector, through the stuffing box, through the wellhead and down the wellbore. Any fluids pumped down a coiled tubing string thus may traverse a significant length of tubing on the surface.
The instant invention anticipates that some live well applications could be more effectively performed with coiled tubing if well fluids were permitted to be circulated up through the tubing rather than up the annulus. For some applications, for instance, the annulus outside of the tubing provides a more effective path for pumping down, leaving the bore for reverse circulating up. E.g., a gravel pack might be more effective if a gravel slurry, were pumped down the broader production tubing—coiled tubing annular region than down the narrower coiled tubing bore. Higher circulation rates might be achieved by pumping the slurry down the annulus. This is particularly true because fluid pumped down the bore must pass through a crossover tool near the bottom. Coiled tubing pack-off and crossover tools can be expensive, and the narrow flow paths inherent in miniature tools offer potential sites for blockages. A potential benefit of the proposed system lies in the elimination of the need for complex combination pack-off and crossover tools. Eliminating coiled tubing crossover tools and their associated packers could lead to improved reliability of operations. The proposed system could also alleviate bridging and lead to improved sand pack uniformity.
Another application where a coiled tubing bore offers a more efficient channel for circulating well fluids up a well than the completion-coiled tubing annulus is a well cleanout. Well cleanout requires raising sand, gravel or particulate matter collected at the bottom of a wellhole. Raising particulate matter, without it settling out, necessitates establishing an upward flow velocity that is a certain multiple of the settling velocity of the particles in the liquid. Additional difficulty and complexity occurs when raising particulate matter in deviated wells. As a result quite high flow rates may be needed to effect a sufficient liquid velocity in an annulus to carry particles up. Sometimes the flow rates required are only achievable using the larger sizes of coiled tubing which can be impractical or else uneconomic. Since the annulus between a coiled tubing and completion typically has a larger cross-sectional area than the tubing bore itself, a lesser flow rate pressure would be needed to achieve the same fluid velocity up the bore.
A third live well application for a dual coiled tubing string in accordance with the instant invention lies in using potentially readily available natural gas to unload liquid from live wells. When natural gas is available at a wellhead, from either the same or neighboring wells, such gas may be quite cost effective as a gas lift fluid. However, pumping natural gas down through coiled tubing must be protected at the surface above the wellhead. Personnel and the environment must be safeguarded from leaks that could develop in the coil before the gas passes below the wellhead.
Historically, transporting well fluids at the surface above a wellhead through normal coiled tubing has been deemed hazardous. Such is currently banned for most offshore operations and is generally unacceptable for many land operations. Coiled tubing becomes bent beyond its yield point when moved off a reel and over a gooseneck by an injector. This plastic bending activity typically takes place with a high pressure applied to the interior of the tubing. A pressure differential across the tubing wall during bending increases stress levels in the tubing and accelerates t
Altman Richard A.
Crabtree Alexander R.
Gavin William G.
Misselbrook John G.
BJ Services Company
Howrey Simon Arnold & White , LLP
Tsay Frank
LandOfFree
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