WELL BARRIER AND METHOD

Abstract

A method for deploying a pump in a well includes attaching a well closure device above a surface control valve, wherein the surface control valve is connected to close a well tubing extending from the well control valve to a predetermined depth in the well. An annular seal and downhole control valve are moved to a selected pump setting depth in the well tubing. The downhole control valve is operable to close the well tubing to fluid flow. The pump is extended into the well tubing at the end of an electrical cable through the well closure device and the well tubing until the pump engages the downhole control valve or the annular seal. The electrical cable is terminated at its surface end with a well penetrator such that the well penetrator seats in the well closure device.

Description

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not Applicable

NAMES OF THE PARTIES TO A JOINT RESEARCH AGREEMENT

Not Applicable.

BACKGROUND

This disclosure relates to the field of well pumps. More particularly, the present disclosure relates to methods and apparatus for deploying pumps such as electric submersible pumps (ESPs) in wells that are in fluid communication with a subsurface fluid reservoir.

Well pumps such as electric submersible pumps (ESPs) can be deployed in wells by connection to an end of an electrical cable such as tubing encapsulated cable (TEC). After the ESP is deployed to a selected depth in the well, the TEC may be suitably terminated outside the surface end of the well and connected to a power supply/control system deployed at the surface. A non-limiting example method for deploying ESPs in wells on such electrical cables is set forth in U.S. Pat. No. 10,036,210 issued to Maclean et al.

Referring to FIG. 1, an ESP 20 is shown attached to one end of an electrical cable 17A such as a tubing encapsulated cable. The ESP 20 may comprise an annular seal such as a packer 26 along its length to close an annular space between the ESP 20 and an interior wall of a production tubing 19 extended into the well. An ESP fluid intake 26 is located on one side of the packer 26, and the ESP discharge 22 is located on the other side of the packer 26 such that fluid is lifted by the ESP 20 into the production tubing 19 to the surface.

To install the ESP 20 using known techniques, it is necessary first to seal the well using, for example, a bridge plug, multiple bridge plugs or any similar seal (not shown) disposed in the production tubing 19 below a Christmas tree 10. The Christmas tree 10 provides valves, e.g., an upper master valve 18 and a lower master valve 11 that hydraulically close the production tubing 19. The outlet side of the upper master valve 18 may be hydraulically connected to a swab valve 12, which may be provided for entry of well intervention tools used to service the well. The Christmas tree 10 may comprise wing valves 14, 16 to enable well servicing and to control flow to a flow line 13 for disposition of fluids from the well. Once the well is sealed, the Christmas tree 10 may be lifted from the upper end of the production tubing 19 and a hanger spool 15 may be attached to the upper end of the production tubing 19. The hanger spool 15 provides a landing for a cable hanger and electrical connector assembly 17 and provides a fluid sealed path and electrical connections for an electrical connector cable 17B. The electrical connector cable 17B is in electrical communication with surface equipment (not shown in FIG. 1), e.g., a power supply/control system, to provide power to the ESP and to communicate control signals and measurement data between the ESP 20 and the surface equipment.

When the hanger spool 15 is installed, the Christmas tree 10 may be reinstalled to the top of the hanger spool 15. The bridge plug (not shown) may then be removed and the ESP 20 inserted into the well at the end of the electrical cable 17A. When the ESP 20 approaches the intended setting depth in the production tubing 19, the electrical cable 17A may be cut and the electrical connector assembly 17 may be attached to the end of the severed electrical cable connected to the ESP 20. The severed electrical cable 17A and attached electrical connector assembly 17 may then be lowered until the electrical connector assembly 17 seats in the hanger spool 15. The electrical connector cable 17B may then be connected to the electrical connector assembly 17 so that operation of the ESP 20 may begin.

In order to perform the foregoing installation technique, several actions are required which may present disadvantages. First is the necessity of lifting the Christmas tree 10 to install the hanger spool 15. In some wells, particularly marine wells, lifting the Christmas tree 10 may require movement of the flow line 13. Moving the flow line 13 may be difficult and expensive. It is also the case that the hanger spool 15 may be a unique item for any particular well, thus requiring a long lead time to make the hanger spool 15 available for use on a particular well.

As stated above, it is also necessary to cut the electrical cable 17A to attach the electrical connector assembly 17. Thus, what remains is a length of electrical cable that may not be reusable for other purpose. Further, if later operation of the well requires moving the ESP 20 to a deeper depth in the well, the severed electrical cable would need to be replaced.

Further, attaching the electrical connector assembly 17 requires making electrical connections to the electrical conductors in the electrical cable 17A. In this way, personnel may be exposed to electric shock, and risk of injury or death, by reason of stray voltages generated by the ESP 20, in particular if the ESP 20 comprises a permanent magnet motor.

There is ongoing need for improved methods to deploy pumps, e.g., ESPs, in wells.

SUMMARY

A method for deploying a pump in a well. A method according to this aspect includes attaching a well closure device above a surface control valve, wherein the surface control valve is connected to close a well tubing extending from the well control valve to a predetermined depth in the well. An annular seal and downhole control valve are moved to a selected pump setting depth in the well tubing. The downhole control valve is operable to close the well tubing to fluid flow. The pump is extended into the well tubing at the end of an electrical cable through the well closure device and the well tubing until the pump engages the downhole control valve or the annular seal. The electrical cable is terminated at its surface end with a well penetrator such that the well penetrator seats in the well closure device.

In some embodiments, the annular seal and the well control valve are deployed on the pump such that the well control valve, the annular seal and the pump are deployed in the well in a single operation.

Some embodiments further comprise electrically connecting a terminated end of the electrical cable to a surface power and control system.

In some embodiments, the electrical cable comprises a tubing encapsulated cable.

In some embodiments, the pump comprises an electric submersible pump.

In some embodiments, the well comprises a bore lining tubular extending at least between the pump setting depth and a permeable formation, an interior of the bore lining tubular being in fluid communication with the permeable formation.

In some embodiments, the surface control valve forms part of a valve assembly comprising at least a valve spool, a swab valve coupled to the valve spool to enable insertion of devices into the well tubing and a flow line valve coupled to the valve spool to control fluid flow from the well tubing to a flow line extending from the flow line valve.

Other aspects and possible advantages will be apparent from the description and claims that follow.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows deployment of a pump on an electrical cable known in the art prior to the present disclosure.

FIGS. 2A and 2B show an example of deployment of a pump on an electrical cable according to the present disclosure.

FIGS. 3A and 3B show an oblique view and an oblique cutaway view, respectively of an example of a rod lock blowout preventer (BOP) usable in accordance with the present disclosure.

DETAILED DESCRIPTION

An example method for deploying a pump, such as an electrical submersible pump (ESP) according to the present disclosure will be explained with reference to FIGS. 2A and 2B, which may be considered together as a single drawing figure herein. A wellhead valve assembly (“Christmas tree”) 10 may be connected to a surface end of a well in which a production tubing 19 is suspended in the well by a tubing hanger (not shown) in a wellhead W. The well may comprise a bore lining tubular such as a casing or liner 19A, which may extend from a particular depth in the well up to the wellhead W, or may terminate at some depth below surface in the borehole of the well. In any event, the bore lining tubular 19A extends upward to at least a depth at which the ESP 20 is to be deployed; the interior of the bore lining tubular 19A may be hydraulically connected, e.g., by perforations (not shown) in the tubular 19A, to a permeable subsurface formation (not shown) from which fluid is to be produced. The Christmas tree 10 may comprise fluid control valves such as an upper master valve 18 coupled to a lower master valve 11, which is itself coupled to the wellhead W. A valve spool 21 may be coupled to the upper master valve 18. A production wing valve 14 which controls fluid flow from the well to a flow line 13 may be coupled to one side of the valve spool 21. A kill wing valve 16 may be coupled to the opposed side of the valve spool 21. A swab valve 12 may be coupled to the upper side of the valve spool 21, whereby intervention tools and other devices may be introduced into the well through the swab valve 12. Pressure in the well may be measured by any form of pressure gauge or transducer 30 in fluid communication with the well when the swab valve 12 is open. There could also be other pressure sensors in the Christmas tree/wellhead area.

In the present example method, a well closure device, e.g., a ram type closure device such as “rod lock” blowout preventer (BOP) 60 may be coupled to the opposed side of the swab valve 12 from that connected to the valve spool 21. The BOP can be any now known or future known BOP. For example, the BOP can be a shear ram in the well, a rod lock BOP, or the like. A non-limiting example of a rod lock BOP that may be used in accordance with the present disclosure is made by Oil Lift Technology Inc., 950 64th Ave. NE, Unit 100, Calgary, Alberta T2E 8S8, Canada. An oblique view of the rod lock BOP 60 is shown in FIG. 3. Returning to FIG. 2, in some embodiments, a pump in sub 32 may be provided between the rod lock BOP 60 and the swab valve 12 to facilitate pumping fluid into the well, e.g., to kill the well.

An annular seal such as a packer, in the present example, a pump anchor packer 40 and downhole control valve (e.g., a downhole safety valve or downhole barrier valve) 38 may be deployed in the production tubing 19 at a depth corresponding to the depth in the well at which an ESP 20 is to be deployed. Deploying the packer 40 and downhole control valve 38 may be performed by any known conveyance that can be extended through the rod lock BOP 60, including, without limitation, coiled tubing, jointed tubing, slickline and electrical cable, whether separately or on the ESP 20 for concurrent deployment in the well. For such deployment, a pressure control device (not shown) such as a wireline or slickline pressure control device, including sufficient lubricator/riser pipe (not shown) to fully enclose all devices to be inserted into the well may be connected to the upper end of the rod lock BOP 60. For such operation, the upper master valve 18 and the lower master valve 11 may be closed to facilitate safe access to the interior of the Christmas tree 10 above the upper master valve 18.

The downhole control valve 38 may be any type of valve used to control flow in a production tubing from a selected depth in a well. Such valve may be, for example and without limitation, operable in any known manner such as electrically, mechanically, hydraulically or by action of deploying the ESP 20 within the production tubing 19.

The downhole control valve 38, the packer 40, and in some examples, the ESP 20 may be lowered into the well until the selected deployment depth is reached, at which depth the packer 40 may be locked in place inside the production tubing 19. In the case of the downhole control valve 38 and the packer 40 being deployed separately, the conveyance (not shown), e.g., slickline, electrical cable, coiled or jointed tubing, may be disconnected from the packer 40 or downhole control valve 38 and removed from the well for subsequent deployment of the ESP 20 on the end of the electrical cable 17A (e.g., tubing encapsulated cable-TEC).

The ESP 20 may then be lowered into the well at the end of the electrical cable 17A until the ESP 20 seats in the packer 40. In some examples, lowering the ESP 20 through the downhole control valve 38 may cause the downhole control valve 38 to open. When the downhole control valve 38 is open, any pressure in the well is contained by the pressure control device (not shown). A well penetrator 34 may be coupled to the surface end of the electrical cable 17A, which may seat in the rod lock BOP 60 when the pump deployment depth is reached. Once the ESP 20 is seated in the packer 40 and the well penetrator 34 is seated in the rod lock BOP 60, the rod lock BOP 60 may be closed about the electrical cable 17A to prevent release of well pressure. The pressure control device (not shown) may then be uncoupled from the rod lock BOP 60, and the electrical cable 17A may be electrically connected (such as by cable 17B) to a surface power and control system 50. As shown in FIG. 2B, the pump intake 28 is exposed below the packer 40 to lift fluid from the interior of the well below the packer 40 and discharge the lifted fluid into the production tubing 19 from the pump discharge 22, whereupon the lifted fluid moves to the surface through the production tubing 19.

A cut away oblique view of the electrical cable 17A with the well penetrator 34 attached and seated on the rod lock BOP 60 is shown in FIG. 3B.

Well pressure is contained within the system, i.e., the Christmas tree 10, the rod lock BOP 60 c/w the electrical penetrator 34, flowline 13, etc. The wellhead W typically has pressure sensor(s) to monitor pressure and there may be downhole pressure sensors also. In the event that there is some unexpected well pressure, e.g., a kick, the downhole control valve 38 can be closed, preventing well fluids from being transported to the surface. The ESP 20 can also be powered down. Any pressure change at the wellhead W can be observed. As a contingency the well can be “killed” by pumping suitable kill fluid into the well via the pump-in sub 32. As an extreme contingency the upper 18 and/or lower 11 master valves can be closed, which will shear through the electrical cable 17 and seal the well. When the well is safe the electrical cable 17A will then be “fished” out of the well and the system reconnected, e.g., by deploying the ESP 20 on a replacement electrical cable.

Depending on well history, well pressures, well locality and other related factors different combinations/contingencies can be applied (well specifics review).

A method according to the present disclosure for deploying a cable-conveyed ESP into a well may provide full pressure control of a live well during pump deployment without the need to “kill” the well or to lift the Christmas tree.

In light of the principles and example embodiments described and illustrated herein, it will be recognized that the example embodiments can be modified in arrangement and detail without departing from such principles. The foregoing discussion has focused on specific embodiments, but other configurations are also contemplated. In particular, even though expressions such as in “an embodiment,” or the like are used herein, these phrases are meant to generally reference embodiment possibilities, and are not intended to limit the disclosure to particular embodiment configurations. As used herein, these terms may reference the same or different embodiments that are combinable into other embodiments. As a rule, any embodiment referenced herein is freely combinable with any one or more of the other embodiments referenced herein, and any number of features of different embodiments are combinable with one another, unless indicated otherwise. Although only a few examples have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible within the scope of the described examples. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.

Claims

1. A method for deploying a pump in a well, comprising: attaching a well closure device above a surface control valve, the surface control valve connected to close a well tubing extending from the well control valve to a predetermined depth in the well;moving an annular seal and downhole control valve to a selected pump setting depth in the well tubing, the downhole control valve operable to close the well tubing to fluid flow;deploying the pump at the end of an electrical cable through the well closure device and the well tubing until the pump engages the downhole control valve or the annular seal; andterminating the electrical cable at a surface end thereof with a well penetrator such that the well penetrator seats in the well closure device.

2. The method of claim 1 wherein the annular seal and the well control valve are deployed on the pump such that the well control valve, the annular seal and the pump are deployed in the well in a single operation.

3. The method of claim 1 further comprising electrically connecting a terminated end of the electrical cable to a surface power and control system.

4. The method of claim 1 wherein the electrical cable comprises a tubing encapsulated cable.

5. The method of claim 1 wherein the pump comprises an electric submersible pump.

6. The method of claim 1 wherein the well comprises a bore lining tubular extending at least between the pump setting depth and a permeable formation, an interior of the bore lining tubular being in fluid communication with the permeable formation.

7. The method of claim 1 wherein the surface control valve forms part of a valve assembly comprising at least a valve spool, a swab valve coupled to the valve spool to enable insertion of devices into the well tubing and a flow line valve coupled to the valve spool to control fluid flow from the well tubing to a flow line extending from the flow line valve.