WELLBORE PUMPS IN SERIES, INCLUDING DEVICE TO SEPARATE GAS FROM PRODUCED RESERVOIR FLUIDS
A pump system for a wellbore includes a production tubing nested within a wellbore. At least two pumps are disposed in the production tubing and are axially spaced apart from each other. One of the pumps is removable from the production tubing while the production tubing remains in place. A fluid intake conduit is disposed outside the production. The fluid intake conduit is in fluid communication with an interior of the production tubing below a lower one of the pumps and at a position of an intake of an upper one of the pumps. At least one fluid discharge conduit is disposed outside the tubing and inside the wellbore. The at least one fluid discharge conduit is in fluid communication with the interior of the production tubing proximate a discharge of the lower one of the pumps and above the upper one of the pumps.
Continuation of International Application No. PCT/IB2017/057503 filed on Nov. 29, 2017. Priority is claimed from U.S. Provisional Application No. 62/440,060 filed on Dec. 29, 2016. Both the foregoing applications are incorporated herein by reference in their entirety.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENTNot Applicable
NAMES OF THE PARTIES TO A JOINT RESEARCH AGREEMENTNot Applicable.
BACKGROUNDThis disclosure relates to the field of producing fluids from underground wellbores, where the fluids need artificial assistance to be transported to the surface.
Wellbores used for the production of fluids disposed in underground formations (for example from a hydrocarbon reservoir) to the surface often must be equipped with artificial lift devices such as downhole pumps to assist pushing fluids to the outlet of the wellbore proximate the surface. A common pump type is electrically driven, and is known as an electrical submersible pump (ESP). To obtain various fluid lift rates to the surface, the length and dimension of the pump determines the fluid flow rate to surface that may be obtained. ESP fluid lift flow rates typically are related to the outer diameter and length of the ESP. Smaller diameter and smaller length corresponds to lower possible flow rates; larger outer diameter and longer pumps may have higher possible flow rates.
Often wellbores include a conduit called a “casing” that has a less than optimum internal diameter for an artificial lift system to be installed, which frequently means that a pump (e.g., an ESP) of smaller outer dimension than may be desirable must be used, and correspondingly results in insufficient fluid lift rates to the surface. Also, wellbores are often deviated (inclined from vertical), which results in a length restriction for the pump(s); pumps generally cannot be exposed to large bending as would be required to install such pumps in a wellbore that has high change in deviation per unit length (“dog leg severity”). As an example, the productive reservoirs in the Barents Sea located north of Norway are at very shallow depths below the seafloor. Highly inclined and/or horizontal wells are often required to make producing hydrocarbons from such reservoirs economically feasible. The dog leg severity of such wells may create challenges in deploying pumps deep enough in such wells to deliver optimum flow and reservoir drainage. It should also be noted that such reservoirs will often produce fluids very close to their bubble point, further creating a need for having pumps as deep into the wellbores as possible.
Another aspect of shallow reservoirs such as may be found in the Barents Sea is that it is remote from shore, and replacing pumps that are permanently mounted onto the production tubing will require lengthy and costly mobilization of a marine drilling unit. Such conditions result in lost production while waiting for the marine drilling unit to be mobilized to the well location and made ready for the well intervention.
If pumps in subsea wells can be replaced by light intervention, as for example by wireline or similar, a less costly vessel can be used. Such vessels will most likely also have much less mobilization time than marine drilling units, which may substantially reduce lost production in case of pump failures.
Hence, there is a need for a solution to the difficulties of installing pumps in highly inclined wellbores, and in particular such wellbores located offshore.
ESPs may suffer from lack of reliability, and therefore it is an advantage to install several pumps as redundancy in a wellbore, so that production is not completely stopped in case of failure of one pump. An alternative, as described in U.S. Pat. No. 9,166,352 issued to Hansen, is to equip a pump with an electrical wet connect system, so that a pump can be retrieved and installed without having to retrieve the entire well completion system.
There are technologies known in the art where power to operate individual wellbore pumps can be engaged and disengaged downhole in the wellbore, as for example an hydraulically activated switch provided by RMS Pumptools, North Meadows Oldmeldrum Aberdeenshire AB51 0GQ, United Kingdom and described in U.S. Pat. No. 8,353,352 issued to Leitch. It is also possible to implement a downhole electronic addressing system, which could be used to engage and disengage electrical power to individual or several wellbore pumps. Operation of a downhole addressing system may be performed using an ESP power cable, or by using a separate cable that may also be used for downhole sensors and the like. Such a switching system may be incorporated into an ESP coupler as described in U.S. Pat. No. 9,166,352 issued to Hansen. Also a downhole switch is described in U.S. Patent Application Publication No. 2015/003717, entitled, “Electric submersible pump having a plurality of motors.”
SUMMARYIn one aspect, the disclosure relates to a pump system for a wellbore. A pump system according to this aspect of the disclosure includes a production tubing nested within a casing in a wellbore or disposed within an open wellbore. At least two pumps are disposed in the production tubing and axially spaced apart from each other. At least one of the at least two pumps is removable from the production tubing while the production tubing remains in place in the wellbore. At least one fluid intake conduit is disposed outside the production tubing and inside the wellbore. The at least one fluid intake conduit is in fluid communication with an interior of the production tubing below a lower one of the at least two pumps and at a position of an intake of an upper one of the at least two pumps. At least one fluid discharge conduit is disposed outside the tubing and inside the wellbore. The at least one fluid discharge conduit in fluid communication with the interior of the production tubing proximate a discharge of the lower one of the at least two pumps and above the upper one of the at least two pumps.
A method for pumping fluid from a wellbore according to another aspect of the disclosure includes operating at least one of at least two pumps disposed in a production tubing disposed in the wellbore. At least one of the at least two pumps is removable from the production tubing while the production tubing remains in place in the wellbore, at least one fluid intake conduit disposed outside the production tubing and inside the wellbore, the at least one fluid intake conduit in communication with an interior of the production tubing below a lower one of the at least two pumps and at a position of an intake of an upper one of the at least two pumps, at least one fluid discharge conduit disposed outside the tubing and inside the wellbore, the at least one fluid discharge conduit in fluid communication with the interior of the production tubing proximate a discharge of the lower one of the at least two pumps and either proximate an intake of or above the upper one of the at least two pumps.
Other aspects and possible advantages of the present disclosure will be apparent from the description and claims that follow.
The present disclosure describes structures wherein a plurality of wellbore fluid pumps can be installed in a wellbore as individual units, where each pump below an uppermost pump transfers fluids to a location above the uppermost pump, or to an area below the uppermost pump, if the uppermost pump is capable of pumping the combined volume delivered from the pumps below. Bypass (flow) conduits may be provided for transporting reservoir fluids from below the lowermost pump to one or more pumps mounted above the lowermost pump, as well as transporting fluids from the various pumps to a location below and/or above the uppermost pump. One or several fluid transport tubes may be disposed between each required pump location may be provided in some embodiments to obtain increased fluid transport rate to surface. The axial distance along the wellbore between the various pumps may be different. By utilizing three pumps, for example, where two pumps in operation provide sufficient fluid flow rate to surface, provides redundancy and more reliable production. If one of the two operating pumps fails, the third pump can be activated to resume the total required fluid lift rate to surface.
Using one or more wet connect coupler(s), as for example the coupler described in patent U.S. Pat. No. 9,166,352 issued to Hansen, the pumps can be replaced by light wellbore intervention instead of having to mobilize and use a much more costly drilling rig.
In some embodiments, a production packer (annular seal between a wellbore casing and a nested production tubing) may be mounted on the production tubing below the pumps, but can also be mounted on the production tubing above the pumps if required. The latter method is more complex, because the packer will need to have bypass devices to enable pass through of the electrical cable. However, pump packers with annular bypass is a commonly available technology today.
In some embodiments, a well completion may consist of a larger outer diameter, permanently installed ESP capable of lifting total required fluid flow rate amount of fluid per combined with one or several retrievable ESPs (e.g., wireline or coiled tubing retrievable ESPs. The retrievable ESPs may function as a back-up to the permanently mounted pump, and may also be sized to together be able to provide the total required fluid flow rate
In some embodiments, a gas separator may be installed below the ESPs, where gas may be discharged to an area above the ESPs. The gas separation system may be retrievable by wireline, coiled tubing or the like, or may also be permanently mounted as part of the production tubing.
While the various embodiments disclosed herein are described in terms of a wellbore having a casing disposed therein, it will be appreciated by those skilled in the art that the various aspects of pump systems according to the present disclosure may be used in wellbores not having casing (“open wellbores”), and the scope of the disclosure should be construed accordingly.
In the example embodiment shown in
Although only a few examples have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the 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 pump system for a wellbore, comprising:
- a production tubing disposed in a wellbore;
- at least two pumps disposed in the production tubing and axially spaced apart from each other, at least one of the at least two pumps removable from the production tubing while the production tubing remains in place in the wellbore; and
- at least one fluid intake conduit disposed outside the production tubing and inside the wellbore, the at least one fluid intake conduit in fluid communication with and providing a fluid transport path between an interior of the production tubing below a lower one of the at least two pumps and at a position of an intake of an upper one of the at least two pumps; and
- at least one fluid discharge conduit disposed outside the tubing and inside the wellbore, the at least one fluid discharge conduit in fluid communication with and providing a fluid transport path between the interior of the production tubing at a discharge of the lower one of the at least two pumps and either at an intake of or above the upper one of the at least two pumps.
2. The system of claim 1 wherein at least the upper one of the at least two pumps is seated in a wet mateable electrical/mechanical connector disposed in the production tubing.
3. The system of claim 1 wherein both the upper one and the lower one of the at least two pumps is seated in a respective wet mateable electrical/mechanical connector disposed in the production tubing.
4. The system of claim 1 further comprising a gas separator disposed in the production tubing below the lower one of the at least two pumps, the gas separator having at least one gas discharge conduit disposed outside the tubing and inside the wellbore, the gas discharge conduits in fluid communication with the interior of the production tubing above the upper one of the at least two pumps.
5. The system of claim 4 further comprising a booster disposed above the upper one of the at least two pumps having an intake in fluid communication with the at least one gas discharge conduit, an outlet of the booster in fluid communication with an interior of the production tubing.
6. The system of claim 3 wherein the gas separator comprises an inner tube nested within an outer tube having fluid entry ports, the inner tube having fluid entry ports at an axial position below the fluid entry ports in the outer tube, a seal disposed between the inner tube and the outer tube disposed at a longitudinal position above the fluid entry ports in the outer tube, the seal having at least one gas discharge tube passing therethrough.
7. The system of claim 1 wherein at least the upper one of the at least two pumps is sealingly engaged to the interior of the production tubing so as to substantially prevent movement of fluid between an interior of the production tubing and an exterior of the at least the upper one of the at least two pumps.
8. The system of claim 1 wherein the at least two pumps comprise electrically submersible pumps.
9. The system of claim 1 further comprising an annular seal element disposed between the production tubing and a casing disposed in the wellbore, the annular seal element disposed at a position below the lower one of the at least two pumps.
10. The system of claim 1 wherein the lower one of the at least two pumps is coupled to the production tubing so as to require removal of the production tubing to remove the lower one of the at least two pumps from the wellbore.
11. The system of claim 1 further comprising a plurality of fluid flow conduits each being in fluid communication with an interior of the production tubing at longitudinal positions corresponding to fluid communication positions of the at least one fluid intake conduit.
12. The system of claim 1 further comprising a plurality of fluid flow conduits each being in fluid communication with an interior of the production tubing at longitudinal positions corresponding to fluid communication positions of the at least one fluid discharge conduit.
13. The system of claim 1 wherein each of the at least two pumps has a fluid pumping rate enabling lift of a full flow rate of fluid from the wellbore to the surface, whereby failure of one of the at least two pumps enables substitution of the other of the at least two pumps to maintain full fluid flow from the wellbore to the surface.
14. The system of claim 1 wherein the at least two pumps have an outer diameter and/or a length such that the at least two pumps are able to move through a point of maximum dog leg severity in the wellbore.
15. The system of claim 1 further comprising at least a third pump disposed in the production tubing intermediate the upper one of the at least two pumps and the lower one of the at least two pumps,
- the at least a third pump having at least one respective fluid intake conduit disposed outside the production tubing and inside the wellbore, the at least one respective fluid intake conduit in communication with the interior of the production tubing below the lower one of the at least two pumps and at a position of an intake of the at least a third pump, the at least a third pump having at least one respective fluid discharge conduit disposed outside the tubing and inside the wellbore, the at least one fluid discharge conduit in fluid communication with the interior of the production tubing proximate a discharge of the at least a third pump and either proximate the intake of or above the upper one of the at least two pumps.
16. The system of claim 15 wherein the at least a third pump is seated in a respective wet mateable electrical/mechanical connector disposed in the production tubing.
17. The system of claim 16 wherein the at least a third pump is removable from the production tubing without removing the production tubing from the wellbore.
18. The system of claim 15 wherein any combination of two of the upper one of the at least two pumps and the at least a third pump has a fluid pumping rate enabling lift of a full flow rate of fluid from the wellbore to the surface, whereby failure of any one of the at least two pumps and the at least a third pump enables substitution of the other of the at least two pumps to maintain full fluid flow from the wellbore to the surface.
19. A method for pumping fluid from a wellbore, comprising:
- operating at least one of at least two pumps disposed in a production tubing disposed in the wellbore,
- at least one of the at least two pumps removable from the production tubing while the production tubing remains in place in the wellbore, at least one fluid intake conduit disposed outside the production tubing and inside the wellbore, the at least one fluid intake conduit in fluid communication with and providing a fluid transport path between an interior of the production tubing below a lower one of the at least two pumps and at a position of an intake of an upper one of the at least two pumps,
- at least one fluid discharge conduit disposed outside the tubing and inside the wellbore, the at least one fluid discharge conduit in fluid communication with and providing a fluid transport path between the interior of the production tubing at a discharge of the lower one of the at least two pumps and either at an intake of or above the upper one of the at least two pumps.
20. The method of claim 19 wherein each of the at least two pumps has a fluid pumping rate enabling lift of a full flow rate of fluid from the wellbore to the surface, whereby failure of one of the at least two pumps enables substitution of the other of the at least two pumps to maintain full fluid flow from the wellbore to the surface.
21. The method of claim 19 further comprising operating at least a third pump disposed in the production tubing intermediate the upper one of the at least two pumps and the lower one of the at least two pumps, the at least a third pump having at least one respective fluid intake conduit disposed outside the production tubing and inside the open wellbore, the at least one respective fluid intake conduit in communication with the interior of the production tubing below the lower one of the at least two pumps and at a position of an intake of the at least a third pump, the at least a third pump having at least one respective fluid discharge conduit disposed outside the tubing and inside the wellbore, the at least one fluid discharge conduit in fluid communication with the interior of the production tubing proximate a discharge of the at least a third pump and either proximate the intake of or above the upper one of the at least two pumps.
22. The method of claim 21 wherein any combination of two of the upper one of the at least two pumps and the at least a third pump has a fluid pumping rate enabling lift of a full flow rate of fluid from the wellbore to the surface, whereby failure of any one of the at least two pumps and the at least a third pump enables substitution of the other of the at least two pumps to maintain full fluid flow from the wellbore to the surface.
Type: Application
Filed: Jun 13, 2019
Publication Date: Sep 26, 2019
Inventor: Henning Hansen (Dolores)
Application Number: 16/440,902