WO2012045771A2

WO2012045771A2 - Well pump installation

Info

Publication number: WO2012045771A2
Application number: PCT/EP2011/067377
Authority: WO
Inventors: Jøren BREDA; Vidar Sten-Halvorsen; Torgeir Braein
Original assignee: Fmc Kongsberg Subsea As
Priority date: 2010-10-06
Filing date: 2011-10-05
Publication date: 2012-04-12
Also published as: WO2012045771A3; NO20101382A1

Abstract

A subsea well arrangement, and an associated method of installation, comprising a submersible pump comprising a pump section (20) and a motor section (22), a cable (30) for supplying power to the pump motor extending upwards of the well, and means for connecting the cable (30) to a power source outside of the well, characterized in that the pump section (20) is anchored to a production tubing (10) in the well, the motor section (22) is releasably attached to the pump section (20) and located above the pump section (20), a power cable is attached to the motor and extending inside the tubing up to a plug (24) located in the tubing hanger of a Christmas tree (4), and that the outside power source is connected to the plug (24).

Description

Well pump installation

The invention relates to a well pump installation and a method for installing and/or retrieving a pump from a subsea well.

When extracting hydrocarbons from a subterranean formation a hole is drilled down to the producing formation which is then cased and production tubing is installed in the well with a Christmas tree on top. Thereafter the casing is perforated to allow hydrocarbons to flow into the tubing and out of the well. The Christmas tree contains the valves and other equipment to ensure safe operation of the production.

Normally the hydrocarbons will flow out of the well freely due to the pressure in the formation. However, as the deposit gets depleted the pressure will drop and the well may have to be shut down when there are still hydrocarbons that can be extracted from the well. It is possible to install means in the well to help lift hydrocarbons to the surface. There are also deposits where the natural formation pressure is too low to "push" the hydrocarbons out of the well.

There are two main ways to help extracting hydrocarbons from the well. Using a gas lift process a gas is pumped partway down the well. When the gas flows upwards it creates a pressure drop in the top of the well that will enable hydrocarbons to flow. This is a method that is widely used but it is costly as there must be installed additional infrastructure and the gas may have to be pumped from a surface facility. Another method is to install a pump in the well to increase the pressure of the flow. These are called electrical submersible pumps (ESP). However the environment in a well is very difficult and can cause electrical motors to break down after only a few years. The pump is normally installed as part of the tubing and therefore the whole production tubing must be pulled when the pump needs to be replaced. Therefore pumps have found most use in land wells where it is easier to gain access to the well.

In a subsea environment the access to the pump system is far more difficult. A subsea well may be located more than a thousand meters below the surface and the ESP system may in addition be installed thousands of meters below the seabed. This increases the challenge of installation since the equipment must also have the capacity to carry the installation cable or wire as well as the weight of the ESP.

In a subsea well there is a need for a ESP system that is easy to install and to retrieve (in the event of failure). This need is addressed according to the present invention as disclosed in the following independent claims with additional features of the invention set forth in the dependent claims and the description below. In the following the invention will be described with reference to the accompanying drawings, where

Fig. 1 is a drawing of a subsea well pump installation,

Fig. 2 is a drawing showing the pump/motor combination in more detail.

Fig. 3 is a drawing of the installation system,

Figs. 4- 8 are drawings of the installation sequence,

Fig. 9 is a drawing showing the pump installed in the well,

Fig. 10 is a drawing of the wellhead PCH

Fig. 1 1 show alternative means for installation, and

Fig. 12 is a drawing of a composite power cable.

In Fig. 1 there is shown a well with a pump installed according to the invention. The well has a wellhead 2 with a Christmas tree 4 connected to the wellhead. The wellhead supports a number of casing strings that is shown in Fig. 3. The Christmas tree has a production outlet 6 controlled by a valve 8. From the Christmas tree there extends a production tubing string 10 down to a producing formation 12.

The pump comprises a pump section 20 connected to an electric motor 22. The pump/motor combination may be assembled and fixed to each other on the surface but in a preferred embodiment the motor and pump is separate and a releasable connector 21 is mounted between the motor and the pump. The reason for that will be explained in more detail later. The pump section 20 is connected to a combined packer and anchoring means 24. This enables the pump to be anchored to the tubing in the well. The anchoring means may be slips expanded into the tubing wall as is well known in the art. The packer isolates the annulus between the pump and the tubing. As part of the packer there may be installed a safety valve 26 that can close off the pump inlet passage.

A power cable 30 extends from the wellhead 2 to the electric motor 22 for supplying power to the motor. A preferred cable may be as shown in Fig. 12. The cable 30 is a composite cable with carbon fibres embedded into a matrix 31. The cable comprises three power conductors 35, each with an insulating layer 33. In addition there is shown an optical cable 34 for carrying signals to or from the motor. The cable may also comprise hydraulic lines 36 for supplying for example chemicals and fluids for operation of hydraulic functions (operate locks/latches, pressure test etc) down into the well. In the drawing three lines are shown but there may of course be more or fewer than three. The composite cable will be designed to carry the weight of the ESP during installation and retrieval, as will be discussed in more detail later. A favourable design is a cable with 30 mm OD and having three conductors with 5 mm diameter. Such a cable will have breaking load of 560 kN. The motor 22 has a connector 23 for connecting the cable to the motor housing. This is preferably a permanent connection that is made up on the surface before installation. The cable extends upwards to the Christmas three 4 and is at its upper end connected to a plug 24. The plug 24 is designed to fit into the crown plug profile in the tubing hanger. To supply power to the motor a special tree cap 26 is used. The tree cap comprises a wet mate connector that, when installed, will mate with a corresponding connector in the plug 24. Power is supplied from a remote location through subsea cable 25.

In use, as shown in Fig. 2, the hydrocarbons will flow from the producing formation and into the well below the pump and then up to the pump inlet, as depicted by the arrow 14. The pump outlet is depicted by arrows 15. The flow will then continue up the tubing (16) and out through the production outlet 6 of the Christmas tree.

Tn Fig. 3 there is shown a typical well layout with an intervention stack mounted on top for installing and retrieving the ESP. In the well there is set a conductor casing normally anchored to a guide base (not shown). Inside this there is a surface casing 104 that is welded to the wellhead 2 in the normal manner. In this example two intermediate casings 105 and 106 are installed in the well and hung off from the

Christmas tree 2. The production tubing is welded to a tubing hanger (not shown) in the Christmas tree and extending down into the well. A production packer 108 seals off the annular space between the tubing 10 and the innermost casing 106. A liner 1 10 may also be arranged in the well, extending into the formation. As shown the Christmas tree has a production outlet 6 controlled by master valve 8 and wing valve 9.

The lubricator stack is mounted on top of the Christmas tree and connected thereto. The lubricator stack comprises a lubricator tube 50, a well control package 52 and upper 54 and lower 56 pressure control heads (PCH). The upper PCH is equipped with a lubricator system for facilitating the passage of a cable through the PCH. Bypass lines 60 is arranged for flushing hydrocarbons out of the lubricator through 64 and into the well. There are provisions 62 for injecting a hydrate inhibitor into the lubricator. For a more detailed understanding of the subsea lubricator stack one is directed to US Patent 7 331 393 and the detailed description there.

Figs. 4 - 8 show the installation sequence for the ESP. Before installation the WCP valves 52 and the lower PCH 56 are closed. The upper PCH is opened and the ESP 20, 22 is lowered into the lubricator suspended from the cable 30 (Fig. 4). The upper PCH is now closed and the lower PCH is opened to allow passage of the pump into the well. The upper PCH allows passage of the cable while sealing the well fluids from the environment. If necessary grease can be supplied to seal around the cable as it is lowered into the well, as described in US Patent 7 331 393.

In this embodiment a safety valve is installed in the tubing above the ESP. When safety valve 32 is near the lubricator, the lower PCH 56 is closed to seal around the cable. Hydrocarbons will now be flushed out of the lubricator before the upper PCH 54 is opened to allow passage for the safety valve. After the safety valve 32 has entered the lubricator the upper PCH 54 is again closed sealingly around the cable 30 (Fig. 5). The lower PCH can now be opened to allow further passage of the ESP and the safety valve into the well (Fig. 6).

As the ESP is further lowered into the well the anchoring plug 24 nears the lubricator. The lower PCH 56 is again closed and hydrocarbons flushed from the lubricator. Now the upper PCH 54 is opened and the assembly is lowered further into the well until the plug 24 has entered the lubricator 50 (Fig. 7). The upper PCH 54 is again closed and the lower PCH 56 is opened. The assemblage is now lowered further into the well until the ESP is in position to be locked to the tubing. At the same time the safety valve is also anchored in the tubing. The tension is now taken off the lifting cable 31 so that the plug 24 can enter and be locked into the tubing hanger. This will then also take the tension off the composite power cable 30.

The cable may be arranged such that it coils along the inside wall of the production tubing, this may be achieved by cable overlength or by telescopic ESP locking arrangement. The cable coiled against the tubing wall may have favourable working condition due to being out of the main production flow and less subject to wear and vibration.

The situation is now as shown in Fig. 1 1. The ESP and plug is anchored into position. A tree cap having a wet mate connector is installed on top of and locked into the Christmas tree. The tree cap connector stabs into a receptacle (not shown) in the plug to enable power, signal and fluids to be supplied to the ESP.

Fig. 9 shows a more detail of the lower PCH 56. The PCH comprises rams 67, 68 that can be opened to allow passage of the larger items, such as the pump and the plug. After passage of the larger items the rams can be closed to enable sealing around the cable as the pump is lowered into the well. A valve 70 with means for cutting the cable may also be included in the PCH 56.

Fig. 10 shows an alternative embodiment. During installation the lower PCH 56 is lowered to the seabed and attached to the wellhead (Christmas tree). At the surface the pump is mounted inside the lubricator pipe and the upper PCH placed on top of the lubricator. In this way the lubricator will function as a container during installation. As mentioned above the PCH rams comprises stripping means but can also open wide to accommodate the larger diameter ESP, safety valve, cable hanger (plug) and so on. In a preferred embodiment flow tubes 72 can be arranged around the cable. The flow tubes are short pieces of pipe that has an inner diameter only slightly larger than the cable. At the surface the cable is inserted into the flow tube and, when the assembly is lowered the flow tubes will be located just above the ESP. When the ESP has passed through the upper PCH the PCH can be closed around the flow tubes and hold these as the ESP is further lowered into the well. When the plug is mounted to the top end of the composite cable, another flow tube can be arranged around the lift wire above the plug.

When the time comes for the plug to pass through the lower PCH< it is opened and the flowtube allowed to slide down into the well. A pressure equalization system 74 can be included in the lubricator.

Normally an ESP assembly is installed together with the tubing and the power cable will then normally be run on the outside of the tubing and fastened thereto. The pump is then normally located above the motor because that enables better cooling of the motor. As mentioned before, the problem then is that to retrieve the assembly the whole tubing must be withdrawn from the well. This is a very costly operation since it will need a rig on the surface to handle the loads. Also the well must be killed by pumping heavy mud into the well to balance the pressure in the well. This may have serious consequences in that it may not be possible to start up the well again because mud has entered the formation and close the pores that enables the flow of oil into the well.

In the present invention it is therefore suggested that the pump section is located below the motor and is detachable from the motor. The pump will normally have a much longer life than the motor. A pump may typically last for up to ten years while a motor may wear out in as little as two years. It will therefore be an advantage to be able to only change out the motor while the pump section is left in the well. Another benefit of that is when the pump and motor is installed separately the length of lubricator can be smaller. An ESP can easily be more than 40 meters long and it is therefore very difficult to have such long lubricator pipe since it is influenced by bending moments from operations and currents and the bending moments can be more difficult to provision for. It will certainly result in a larger and heavier lubricator to enable sufficient stiffness. Therefore, in the preferred embodiment, the pump is installed first. The pump can be run on a standard wire, cable or, if desired, coiled tubing. The lower PCH will in that case not be used. Next the pump section is installed as described above. When the pump stops working it will almost certainly be due to the motor and therefore, when the is retrieved it can be done using a light intervention vessel instead of a costly rig.

The invention also facilitates retrospective instaliation of the ESP in existing wells. The upper DHSV (safety valve) 32 must in this case be locked open before pump installation.

Claims

1. A subsea well arrangement comprising a submersible pump comprising a pump section (20) and a motor section (22), a cable (30) for supplying power to the pump motor extending upwards of the well, and means for connecting the cable (30) to a power source outside of the well, characterized in that the pump section (20) is anchored to a production tubing (10) in the well, the motor section (22) is releasably attached to the pump section (20) and located above the pump section (20), a power cable is attached to the motor and extending inside the tubing up to a plug (24) located in the tubing hanger of a Christmas tree (4), and that the outside power source is connected to the plug (24).

2. A subsea well arrangement as claimed in claim 1 where the power cable (30) is a composite cable.

3. A subsea well arrangement as claimed in claim 2 where the composite cable comprises at least two copper conductors, an optical line and at least one fluid line.

4. A subsea well arrangement as claimed in claim 2 where the composite cable is a load carrying cable used to carry the weight of the pump during installation or retrieval.

5. A subsea well arrangement as claimed in claim 1 where the plug has a wet mate connector for connecting the lines in the cable to lines in a tree cap.

6. A subsea well arrangement as claimed in claim 1 where the tree cap is

connected with a remote installation.

7. A subsea well arrangement as claimed in claim 1 where, during installation, a subsea lubricator is mounted on top of the well.

8. A subsea well arrangement as claimed in claim 7 where the subsea lubricator comprises a lubricator pipe and a first pressure control head located on top of the lubricator pipe.

9. A subsea well arrangement as claimed in claim 7 where the subsea lubricator comprises a second pressure control head located between the lubricator pipe and the top of the well.

10. A subsea well arrangement as claimed in claim 7 where the pressure control heads have means for sealing around the composite cable when the pump is run into or out of the well.

1 1. A subsea well arrangement as claimed in claim 7 where the pressure control heads comprise a grease injection system.

12. A method for installing a submersible pump in a subsea well, the pump comprising a pump section (20) and motor section (22), the motor section (22) being releasably attached to the pump section (20) and located above the pump section (20), the method comprising the following steps,

-attach a composite cable to the pump and lower the pump into a

subsealubricator having upper (54) and lower (56) pressure control heads, -open the lower pressure control head (56) and lower the pump further into the well,

-attach a plug (24) to the upper end of a composite cable,

-attach another cable or wire to the plug (24) and lower the plug (24) into the subsea lubricator while the pump is lowered further into the well,

-open the lower pressure control head to allow entry of the plug (24) into the

Christmas tree (4),

-anchoring the pump in a production tubing (10) of the well, and

-anchoring the plug (24) in the Christmas tree (4).

13. A method as claimed in claim 12 further comprising the step of locking the pump to the production tubing (10) in the well.

14. A method according to claim 12 where the motor section (22) and the pump section (20) can be installed independently of each other.

15. A method as claimed in claim 12 where the lubricator is retrieved to the surface after operations.