CT drilling rig

Details CT drilling rig CT drilling rig

2000-12-15

2003-04-29

Neuder, William (Department: 3672)

Wells

Processes

Assembling well part

C166S085100, C175S162000

Reexamination Certificate

active

06554075

ABSTRACT:

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
Not Applicable.
BACKGROUND OF THE INVENTION
1. Field of the Invention
The present invention generally relates to rigs for deploying bottom hole assemblies (“BHAs”) that are connected to a flexible umbilical. More particularly, the present invention relates to transportable rigs for deploying multi-segment BHAs connected to composite coiled tubing. In another aspect, the present invention relates to methods for deploying BHAs connected to flexible umbilicals. In still another aspect, the present invention relates to methods of automating the deployment of BHAs connected to a flexible umbilical.
2. Description of the Related Art
Many existing wells include hydrocarbon pay zones which were bypassed during original drilling and completion operations. Well operators or owners chose not to complete these zones because these bypassed zones were not economical to complete and produce. That is, the expected recovery rate of hydrocarbons from a bypassed zone did not justify the cost of implementing the downhole equipment need to complete and produce the bypassed zone. For example, offshore drilling platforms can cost upwards of $40 million to build and may cost as much as $250,000 a day to lease. Such costs preclude the use of such expensive platforms to exploit hydrocarbon pay zones that may not produce hydrocarbons in sufficient quantity or rates to offset these costs. Thus, often only the larger oil and gas producing zones are completed and produced because those wells are sufficiently productive to justify the cost of drilling and completion using conventional offshore platforms. Similar economic considerations also come into play for land based wells. Because many major oil and gas fields are now paying out, there is need for a cost effective method of producing these previously bypassed hydrocarbon pay zones.
Cost effective production of bypassed zones requires, in part, drilling and completion systems and methods that can efficiently reach these subterranean formations. Also required are surface support and control systems that can economically deploy these drilling and completion systems and methods.
The system and methods disclosed in commonly-owned U.S. application Ser. No. 09/081,961, entitled “Well System,” filed on May 20, 1998, now U.S. Pat. No. 6,296,066, which is hereby incorporated herein by reference for all purposes, addressed the first need. One embodiment of a system disclosed in the “Well System” application for economically drilling and completing the bypassed pay zones in existing wells includes a bottom hole assembly disposed on a composite umbilical (hereinafter a “CCT BHA”) made up of a tubing having a portion thereof which is preferably non-metallic.
Referring to
FIG. 1
, there is shown a BHA
10
disposed in a lateral borehole
12
branching from a primary wellbore
14
. BHA
10
is operatively connected to a composite coiled tubing umbilical
16
and may include a drill bit and other modules or segments. BHA segments may include a gamma ray and inclinometer and azimuth instrument package, a propulsion system with steerable assembly, an electronics section, a resistivity tool, a transmission, and a power section for rotating the bit.
Because composite tubulars are much lighter and more flexible than steel pipe and steel coiled tubing, the operational reach of a drill or working string formed of composite coiled tubing
16
is significantly increased for at least two reasons. One reason is that the relative lightweight nature of composite coiled tubing lessens the power required of downhole tractors and other transport systems.
A closely related second reason is that composite tubing can be designed to be neutrally buoyant in drilling mud. In an ordinary case, high pressure drilling mud is pumped from the surface to the BHA
10
via the composite umbilical
16
. The hydraulic pressure of the drilling mud is used to power the propulsion system and to rotate the drill bit. The drilling mud exits the BHA
10
through nozzles located on the drill bit. The exiting drilling mud cools the drill bit and flushes away the cuttings of earth and rock. Drilling mud returns to the surface via the annulus
19
defined by the wall
21
of lateral wellbore
12
and composite coiled tubing
16
. The materials for composite tubing
16
and the drilling mud can be selected so as to achieve neutral buoyancy in the drilling mud in which the composite coiled tubing is immersed. Thus, downhole tools, such as propulsion systems, need only provide sufficient force to tow neutrally buoyant composite coiled tubing
16
through wellbore
12
and to plan a force on the drill bit.
The profitability of bypassed zones also depends, in part, on the costs associated with introducing, operating, and retrieving a drilling and completion system, such as a CCT BHA, at a given well site. Prior art drilling rigs have inherent drawbacks that reduce the cost effectiveness of utilizing drilling and completion systems to construct new wells and workover existing wells. Some of these drawbacks are discussed below.
The prior art does not disclose rigs that may be readily moved from one well to another on a well site. For example, as is well known in the art, subterranean hydrocarbon fluids are typically under significant pressure. During drilling, this pressure must be controlled to prevent hydrocarbon fluids from surging up the wellbore and causing a “blow-out” at the surface. Blowout preventers are attached to the wellhead to control this well pressure. In order to contain this well pressure, it is important that the BOP's and related components making up the BOP stack be tightly sealed. Before a prior art drilling rig supporting a CCT BHA system can be moved from a first well to a second well at a given well site, the valves and other joints making up the BOP stack must be disassembled. These valves and joints must be reconnected and tested after the rig has been moved above the second well. Considerable time and effort may be saved if this disassembly procedure could be minimized. Thus, what is needed is a rig that provides for the movement of a BOP stack as an integral unit to minimize the time and costs associated with servicing multiple wells at a given well site.
The prior art also does not disclose rigs that are readily moved between well sites to support drilling and completion operations. Prior art rigs are generally not designed to be connected and disconnected at several successive well sites. Thus, well construction or well workover often require a new rig to be constructed at each well site. What is needed is a rig that can be constructed at a given well site and then disassembled and moved to a second well site for re-use. Such a rig would minimize the need for additional rig superstructures.
The prior art also does not disclose a rig that effectively supports the introduction of a CCT BHA into a well. A CCT BHA designed in accordance with the above description may be over fifty feet in length. Because handling such a long BHA can be unwieldy, the many components making up the BHA are usually assembled into multiple BHA modules or segments. These BHA segments are in turn connected together to form a complete BHA. Such a procedure using prior art rigs is cumbersome because prior art rig do not provide means to mechanically manipulate and dispose successive BHA segments into a well. Thus what is needed is a rig that facilitates the deployment of BHA segments into a well.
As can be seen, prior art rigs are not cost effective with respect to service multiple wells. Moreover, prior art rigs limit the economical use of CCT BHAs in servicing bypassed wells and also increase the cost of constructing new wells.
The present invention overcomes the deficiencies of the prior art.
SUMMARY OF THE INVENTION
The preferred embodiment of the present invention includes a modular rig fitted with a stabilizer for lifting/lowering an injector and BOP stack and a powered arm adapted to manipulate the BHA segments. The rig includes a tower mad

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