Wells – Processes – Placing or shifting well part
Reexamination Certificate
2000-04-26
2003-06-03
Bagnell, David (Department: 3672)
Wells
Processes
Placing or shifting well part
C166S193000, C166S318000, C166S332400, C166S374000
Reexamination Certificate
active
06571880
ABSTRACT:
FIELD OF INVENTION
This invention relates generally to equipment used in the drilling, completion and workover of subterranean wells and more specifically, to the control of drilling fluids, completion fluids, workover fluids, cement, and other fluids in a casing or other tubular string within a wellbore.
BACKGROUND
The process of drilling subterranean wells to recover oil and gas from reservoirs consists of boring a hole in the earth down to the petroleum accumulation and installing pipe from the reservoir to the surface. Casing is a protective pipe liner within the wellbore that is cemented into place to ensure a pressure-tight connection of the casing to the earth formation containing the oil and gas reservoir. The casing is run a single joint at a time as it is lowered into the wellbore. On occasion, the casing becomes stuck and is unable to be lowered into the wellbore. When this occurs, load must be added to the casing string to force the casing into the wellbore, or drilling fluid must be circulated down the inside diameter of the casing and out of the casing into the annulus in order to free the casing from the wellbore. To accomplish this, it has traditionally been the case that special rigging be installed to add axial load to the casing string or to facilitate circulating the drilling fluid.
When running casing, drilling fluid is added to each joint as it is run into the well. This procedure is necessary to prevent the casing from collapsing due to high pressures within the annulus inside the wellbore exterior to the casing. The drilling fluid acts as a lubricant which facilitates lowering the casing within the wellbore. As each joint of casing is added to the string, drilling fluid is displaced from the wellbore. The prior art discloses hose assemblies, housings coupled to the uppermost portion of the casing, and tools suspended from the drill hook for filing the casing. These prior art devices and assemblies have been labor intensive to install, required multiple such devices for multiple casing string sizes, have not adequately minimized loss of drilling fluid, and have not been multi-purpose. Further, disengagement of the prior art devices from the inside of the casing has been problematic, resulting in damage to equipment, increased downtime, loss of drilling fluid, and injury to personnel.
Circulating of the drilling fluid is sometimes necessary if resistance is experienced as the casing is lowered into the wellbore. In order to circulate the drilling fluid, the top of the casing must be sealed so that the casing may be pressurized with drilling fluid. Since the casing is under pressure, the integrity of the seal is critical to safe operation and to minimize the loss of the expensive drilling fluid. Once the casing reaches the bottom, circulating of the drilling fluid is again necessary to test the surface piping system, to condition the drilling fluid in the hole and to flush out wall cake and cuttings from the hole. Circulating is continued until at least an amount of drilling fluid equal to the volume of the inside diameter of the casing has been displaced from the casing and the wellbore. After the drilling fluid has been adequately circulated, the casing may be cemented into place.
The purpose of cementing the casing
500
(See FIG.
3
A through
FIG. 3C
) is to seal the casing to the wellbore formation. In order to cement the casing within the wellbore
502
, hereinafter the assembly to fill and circulate drilling fluid is generally removed from the drilling rig and a cementing head apparatus installed. This process is time consuming, requires significant manpower, and subjects the rig crew to potential injury when handling and installing the additional equipment to flush the mud out with water or other chemical hereinafter prior to the cementing step. A special cementing head or plug container is installed on the top portion of the casing being held in place by the elevator. The cementing head includes connections for the discharge line of the cement pumps, and typically includes a bottom hereinafter
506
and top wiper plug hereinafter
508
. Since the casing and wellbore are full of drilling fluid, it is necessary to inject a spacer fluid to segregate the drilling fluid from the cement to follow. The hereinafter bottom cementing plug hereinafter
506
is used to wiped the inside diameter of the casing and serve, in conjunction with the spacer fluid, to separate the drilling fluid from the cement as the cement is pumped down the casing string hereinafter
500
. Once the calculated volume of cement required to fill the annulus has been pumped, the top plug hereinafter
508
is released from the cementing head. Drilling fluid or some other suitable fluid is then pumped in behind the top plug, thus transporting both plugs and the cement contained between the plugs to an apparatus at the bottom of the casing known as a float collar hereinafter
510
. Once the bottom plug hereinafter
506
seals the bottom of the casing, the pump pressure increases, rupturing, for example, a diaphragm in the bottom of the plug hereinafter
506
and allowing the calculated amount of cement to flow hereinafter as indicated by flow lines
512
from the inside diameter of the casing to a certain level with the annulus hereinafter
504
being cemented. The annulus hereinafter
504
is the space within the wellbore between the inside diameter (“ID”) of the wellbore and the outside diameter (“OD”) of the casing string. When the top check valve closes, keeping the cement from flowing from the OD of the casing back into the ID of the casing.
The prior art typically discloses separate devices and assemblies for (i) filling and circulating drilling fluid; and (ii) cementing operations. The prior art devices for filling and circulating drilling fluid disclose a packer tube, which requires a separate activation step once the tool is positioned within the casing. The packer tubes are known in the art to be subject to malfunction due to plugging, leaks, and the like, leading to downtime. Since each step in the well drilling process is potentially dangerous, time consuming, labor intensive and therefore expensive, there remains a need in the art to minimize any downtime. One advantage in this art is described in U.S. Pat. No. 5,735,348, issued on Apr. 7, 1998 to Samuel P. Hawkins for “Method and Multi-Purpose Apparatus for Dispensing and Circulating Fluid in Wellbore Casing,” some of the components of which can be used, as but one example, in using the present invention.
REFERENCES:
patent: 3768556 (1973-10-01), Baker
patent: 4042014 (1977-08-01), Scott
patent: 4246968 (1981-01-01), Jessup et al.
patent: 4934460 (1990-06-01), Coronado
patent: 5048611 (1991-09-01), Cochran
patent: 5443122 (1995-08-01), Brisco
patent: 5960884 (1999-10-01), Echols
patent: 6003607 (1999-12-01), Hagen et al.
patent: 6053250 (2000-04-01), Echols
Bates Robert A.
Butterfield, Jr. Charles A.
Hawkins Samuel P.
Latiolais, Jr. Burney J.
Laurel David F.
Bagnell David
Frank's International, Inc.
Gay Jennifer H
The Matthews Firm
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