Wells – Processes – Placing or shifting well part
Reexamination Certificate
1999-09-27
2001-12-11
Bagnell, David (Department: 3672)
Wells
Processes
Placing or shifting well part
C166S106000
Reexamination Certificate
active
06328111
ABSTRACT:
TECHNICAL FIELD
This invention relates in general to installing an electrical submersible pump assembly in a live well that may contain pressure and in particular to methods for installing an ESP in a way to maintain at least two pressure barriers while at all times personnel are located at the well.
BACKGROUND ART
Electrical submersible pumps are commonly used in oil and gas wells for producing large volumes of well fluid. An electrical submersible pump (hereinafter referred to “ESP”) normally has a centrifugal pump with a large number of stages of impellers and diffusers. The pump is driven by a downhole motor, which is a large three-phase AC motor. A seal section separates the motor from the pump for equalizing internal pressure of lubricant within the motor to that of the well bore. Often, additional components will be included, such as a gas separator, a sand separator and a pressure and temperature measuring module. Large ESP assemblies may exceed 100 feet in length.
An ESP is normally installed by securing it to a string of production tubing and lowering the ESP assembly into the well. Production tubing is made up of sections of pipe, each being about 30 feet in length. The well will be dead, that is not be capable of flowing under its own pressure, while the pump and tubing are lowered into the well. To prevent the possibility of a blowout, a kill fluid may be loaded in the well, the kill fluid having a weight that provides a hydrostatic pressure significantly greater than that of the formation pressure. During operation, the pump draws from well fluid in the casing and discharges it up through the production tubing.
While kill fluid provides safety, it can damage the formation by encroaching into the formation. Sometimes it is difficult to achieve desired flow from the earth formation after kill fluid has been employed. The kill fluid adds expense to a workover and must be disposed of afterward. ESPs have to be retrieved periodically, generally around every 18 months, to repair or replace the components of the ESP. It would be advantageous to avoid using a kill fluid. However, in wells that are live, that is wells that contain enough pressure to flow or potentially have pressure at the surface, there is no satisfactory way to retrieve an ESP and reinstall an ESP on conventional production tubing.
Coiled tubing has been used for a number of years for deploying various tools in wells, including wells that are live. A pressure controller, often referred to as a stripper or blowout preventer, is mounted at the upper end of the well to seal around the coiled tubing while the coiled tubing is moving into or out of the well. The coiled tubing comprises steel tubing that wraps around a large reel. An injector grips the coiled tubing and forces it from the reel into the well.
The preferred coiled tubing for an ESP has the power cable inserted through the coiled tubing. Various systems are employed to support the power cable to the coiled tubing to avoid the power cable parting of its own weight. Some of the systems utilize anchors that engage the coiled tubing and are spaced along the length of the coiled tubing. Another uses a liquid to provide buoyancy to the cable within the coiled tubing. In the coiled tubing deployed systems, the pump discharges into a liner or in casing. A packer separates the intake of the pump from the discharge into the casing. Although there are some patents and technical literature dealing with deploying ESPs on coiled tubing, only a few installations have been done to date. To applicant's knowledge, none of these installations involve deploying an ESP on coiled tubing into a live well.
While deploying tools within a live well, safety rules require that while workers are nearby, there must be two independent pressure barriers to prevent a blowout. It is known in the prior art to install a packer downhole then land a stinger portion of an ESP in the bore of the packer. There is also prior art that suggests that a safety valve may be incorporated with the packer to provide a first safety barrier.
The second pressure barrier has been proposed in the prior art to be located at the surface. Blowout preventers (BOP) are well known that will seal on cylindrical members and still allow downward movement of that cylindrical member. Some types have an annular element that is deformed into sealing engagement with whatever cylindrical member is located therein, regardless of the diameter. Ram-types have two separate members, each with a semi-cylindrical concave inner profile, that are forced against a cylindrical object of a predetermined diameter. However, ESP assemblies are made up of connections between the various components that present discontinuities in the cylindrical configurations of the components. The connections typically are flanged and have smaller outer diameters than the components. A BOP would not be able to seal on a connection as it is lowered past because of the discontinuity. Positioning the ESP assembly in an isolation chamber below a coiled tubing lubricator and above a BOP on the wellhead would allow an upper pressure barrier to be maintained at all times. However, the length of the ESP assembly in many cases makes this solution impractical.
Snubbers are used for lowering tools into a well, particularly where a draw works is not available. A snubber mounts on top of a BOP and has hydraulic rams to raise and lower a set of tubing slips. A lower second set of slips holds the equipment while the top slips get another “bite”. Snubbers may be used to pull equipment from a well or force the equipment into the well, sometimes through deviations or collapsed sections of casing. Snubbers have occasionally been used to install and retrieve ESP assemblies, but not with any live wells.
Technical literature has discussed deploying an ESP and coiled tubing in a live well. However, the literature does not address all of the concerns mentioned above concerning maintaining two pressure barriers at all times.
SUMMARY OF THE INVENTION
This invention provides several methods for installing a submersible pump assembly in a live well. In some of the methods, an upper pressure barrier is installed in the well at a depth lower than a length of the submersible pump assembly. The upper pressure barrier defines a chamber in the well that is isolated from any pressure in the well below. This allows the ESP to be safely lowered on a line into the chamber because the chamber will not contain pressure. Once in the chamber, the operator seals around the line, releases the upper pressure barrier and lowers the ESP into the well to a desired depth. The upper pressure barrier mentioned maintains one barrier until it is released, then the coiled tubing lubricator serves as the upper pressure barrier. A lower pressure barrier may be maintained at all times by installing a packer with a valve in the well prior to installing the upper pressure barrier.
In one embodiment, the upper pressure barrier is lowered in a collapsed configuration that is significantly smaller than its expanded or set diameter. After the submersible pump assembly is located in the chamber and the line sealed by the lubricator, the pressure barrier is collapsed and withdrawn along a path that is lateral of the submersible pump assembly. In one of the variations of this embodiment, the upper pressure barrier is a packer that is lowered on a string of coiled tubing through an annulus between a casing and a liner. In another variation, the upper barrier is lowered in a collapsed configuration through a string of tubing located off center in the well. The packer passes below the laterally deployed tubing and sets in the casing below the tubing. The upper pressure barrier is retrieved through the laterally disposed tubing.
In another embodiment, the upper pressure barrier comprises an upper packer that has a throughbore containing a valve and an open upper end. The upper packer is set in the casing or in a liner at a depth greater than the length of the ESP assembly. While the valve is closed, the ESP
Bearden John L.
Bebak Kenneth T.
Brookbank Earl B.
Cox Don C.
Fordyce Ronald S.
Bagnell David
Baker Hughes Incorporated
Bracewell & Patterson L.L.P.
Dougherty Jennifer
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