The invention relates to a rotor-dynamic, centrifugal pump for use in pumping hydrocarbons and water in a downhole application. Centrifugal pumps for use in downhole applications are previously known. These pumps employ a so-called multi-stage principle, where the pump consists of a plurality of vertically arranged stages. One stage consists primarily of an impeller and a diffuser. The impeller is attached to a common shaft which runs through all stages, and this shaft is driven by an electric motor. An example of this technique is the ESP pump (Electrical Submersible Pump) which can be found on the market today. The reason a plurality of stages is used is that a stage has a limited capacity for supplying a pressure increase. To obtain sufficient pressure, pumps of this type must use several stages, coupled in series, one on top of the other. There are however some disadvantages associated with existing multi-stage pumps, such as for instance, all the stages are driven by one motor, which means that the whole pump stops if the motor comes to a standstill. In addition, the existing structures are long as the motor is mounted below the pump stages. This is a problem in connection with well deviation. Today's pumps are moreover subject to problems associated with bearing lifetime and wear due to cavitation.

Production of hydrocarbons, and for that matter also water for use in the recovery of hydrocarbons and for other purposes, takes place from reservoirs that lie deep in the rock beneath the surface of the earth. The vertical distance from the surface down to the reservoirs may vary from several hundred metres to several thousand metres. The actual production takes place either by using artificial lifting or in that the reservoir liquids, which may contain dissolved or free gas, flow to the surface through a borehole/well because the pressure in the reservoir is higher than at the surface. Artificial lifting is a generic term for different methods and techniques which can be used for this production. This invention comprises equipment for improving the lifting of hydrocarbons (with or without gas) and/or water to the surface. Choice of method for artificial lifting is made on the basis of conditions in the reservoirs, the nature of the oil, and the depth and path of the borehole/well. In addition, importance is given to the location of the field (onshore or offshore) and the infrastructure of the area, such as access to electric power and gas at the location in question. On the basis of these parameters, the field operator can, with the aid of the invention, construct a plant which gives optimal total economy based on the production properties of the reservoir, investment in equipment and operating costs.

At onshore fields with relatively shallow reservoirs, a system known as a sucker rod pump is often chosen. In this system, the actual driving apparatus is located on the surface, connected to a pump unit down in the well via a pump rod. The challenges of this system are a relatively large driving apparatus that is located above and close to the wellhead, friction between pump rod and the pipe wall in the well, production of sand from the reservoir and a system efficiency factor of 0.4. There are also limitations as to how deep this type of pump system can be located based on material/strength limitation of the pump rod. The systems have limited lifting capacity, and are therefore used at low production rates. The design of the system per se, together with operating conditions, such as sand production, means that they suffer frequent operational interruptions. Besides increasing the direct operating costs, this results in costs associated with delayed production. The stroke length of the actual pump unit in a sucker rod pump is two to three metres, and the frequency is from one to ten strokes per minute. US Patent 5, 179,306 describes a principle in which the pump unit in a sucker rod pump is run by a double-acting DC linear motor that is located downhole together with the pump unit, which is done to avoid the challenges associated with the actual pump rod. j ESPCP and PCP are also systems that are used for artificial lifting. In principle, these are two similar pumps with the difference that the ESPCP (Electrical

Submersible Progressive Cavity Pump) is driven by an electric motor which is located downhole, whilst the PCP (Progressive Cavity Pump) is driven by a motor that is located on the surface. The power for a PCP is transmitted from the surface to the pump down in the well via a pump rod, in the same way as for a sucker rod pump. The pumping principle employed in these pumps is that often termed a screw pump inasmuch as a rotor moves in a circular path within a specially designed pump housing. The ESPCP may be used in both offshore and onshore installations, whilst the PCP is used only on onshore fields. Pumps of this type are regarded as being highly suitable for production of heavy (viscous) oils, and they are generally considered to have an efficiency factor that is better than the ESP which is described in the next paragraph.

The Electrical Submersible Pump (ESP) is a pump type that is frequently used for artificial lifting in both onshore and offshore installations. The pump is mounted down towards the bottom of the well as an integral part of the production tubing, and this means that if it fails, the whole tubing must be pulled out of the well. The pump itself consists primarily of an electric motor in the bottom, out from which there runs a shaft on which impellers and diffusers are mounted in several stages. The number of stages is determined by the necessary lifting height. The liquid is sucked into the bottom of the pump and for each stage the pressure increases, and large pumps may have more than 250 - 300 stages. To reduce the number of stages, the rotational speed can be increased, which gives a reduction in the total length of the pump. US Patent 4,278,399 describes a solution for a more efficient pump stage in an ESP. This is done in principle by reducing the thickness of the material of the pump housing so as to allow the impellers to have a larger radius. The efficiency factor of such pumps is reckoned to be about 0.3, and the volume flow may vary from a few hundred barrels a day to 20-30,000 bbl/d. The electric motor in the pump receives power supplied from the surface through a special cable which is fastened to the outside of the production tubing, and the system is controlled from the surface with the aid of a system known as VSD (Variable Speed Drive). VSD converts AC to DC and back to AC with different frequencies. This causes wear on the electric cables and connections and may lead to earthing problems. Normally, induction motors are used to drive the actual pump and, owing to the need for a large amount of power at high rates and deep wells, they are relatively long. These motors have little clearing between stator and rotor, which means that small bends (dog legs) in the well path may create contact between rotor and stator and result in breakage. The same may happen as a result of vibrations in the motor when long motors are involved (a motor of 250 HP is 20 m long). Due to these conditions, the industry has developed Permanent Magnet (PM) motors which have a more robust design. The mechanical challenges associated with ESP are wear and overheating of the electric motor, which PM is presumed to handle in a better manner. At the same time, large axial forces are generated in the pump itself.

Various solutions exist that have been developed to improve this situation. As an example mention may be made of US Patent 5,201 ,848, which describes an impeller that does not contribute to the lifting of liquid, but which generates an upwardly directed force on the shaft. This is effected in that the main impeller, which contributes to lifting, is mounted on a second impeller of the same volume, the latter having no supply of liquid. Thus, a dynamic pressure is generated in the pump stage, which means that the static pressure further down the pump stage provides a lift which counteracts the downward directed axial forces.

Besides the said mechanical problems, ESP systems have problems in handling production of large amounts of sand and other solid particles such as scale. In addition, cavitation occurs when free gas is produced. Both these situations cause wear of the impellers. Free gas is also a problem for the electric motor itself since the gas has a poorer capacity for conducting away inherent heat generated by the electric motor. All these conditions mean that an ESP system is presumed to have an average lifetime of about 1.5 years. The costs involved in replacing an ESP will vary with the depth of the well since the whole production tubing must be pulled out. In addition to the direct costs of the operation, which involves the use of a drilling rig, there are the costs of delayed production.

Gas lifting is frequently used as artificial lifting on offshore installations where there is access to produced gas from the separator plant. The principle is based on reinjecting produced gas into the annulus between the production tubing and the casing (production annulus) and down towards the production packer at the bottom of the well. Gas lift valves are mounted at different levels in the production tubing. These are one way valves that allow the gas in the annulus to flow into the production tubing so that the weight of the hydrostatic column inside the tubing is reduced, thereby also reducing the counter-pressure on the reservoir so that the reservoir pressure itself can force the produced liquids to the surface. In principle, gas lifting is an efficient system, but it requires investment in own gas compressors, surface flow pipes, annulus safety valves (ASV), gas lift valves (GLV) and gas-tight pipe threads in the casing. The system may be difficult to operate optimally because the mixture ratio between oil, water and possible gas produced from the reservoir will vary with shorter and longer time intervals. In addition, reinjected gas in the production annulus may leak out into the outer annulus through the casings. To reduce the danger of uncontrolled discharge of gas in a possible system accident, a number of oil companies now wish to develop a V0 version of GLV so that they can remove ASV, as it has been found that these valves are vulnerable to leakages. This change is contributing to an increase in the investment costs for gas lifting.

Single and double-acting piston pumps for use in artificial lifting are previously known. Apart from different designs of the actual pump housing (the pistons) and inlet and outlet valves, there are several different drive mechanisms for the pumps. These may be anything from electromagnetic motor solutions to solutions involving linear motors. In addition, a single-acting piston pump is known that is driven by an induction motor which in turn drives a hydraulic unit, which in its turn drives the piston and valves. This particular solution is designed for operation of more than one single-acting piston in the pump. A common feature of all the pumps is that they are designed to be installed at the bottom of the well. US Patent 1 ,740,003 teaches an electrically driven double-acting piston pump. To turn the piston movement, the phase of the motor must be changed so that it turns in the opposite direction. With a frequency of between 30 and 60 strokes per minute, there is substantial wear on the contacts that are to reverse the electric current and substantial heat generation each time the piston is to change direction. As yet no- one has managed to make linear motors practical and commercially viable, in part because there is a surge in power consumption each time the motor is to change direction.

The pump according to the invention comprises several steps, which in turn are divided into one or more pump stages. A pump stage comprises an impeller and a diffuser. A step is defined as comprising a motor which drives one or more pump stages in the step, and according to an aspect of the invention, the pump includes several steps in order for the apparatus to have sufficient lifting capacity. The pump according to the invention overcomes the disadvantages associated with the situation where only one electric motor is to drive all the pump stages inasmuch as the invention is characterised in that it uses a motor in each step. The motor may also drive two or more pump stages in a step via one shaft. According to the invention, the pump is equipped with motors which are configured as ring motors (i.e., liquid can flow in the centre of the motors) at each step - and that there are several steps in the pump in order to obtain sufficient lifting capacity. _^ This is in contrast to known pumps which only have one motor that does not allow liquid to flow through the centre thereof. According to a preferred embodiment, the pump according to the invention consists of up to about three pump stages in a step in order to obtain sufficient lifting, but more pump stages are possible. It is an advantage that the pump has "redundancy" - i.e., if the motor in a step stops, all the other steps will be able to continue to pump. If a pump has too many pump stages in a step that stops, the friction loss in the step will be so great (liquid must flow past impellers that are stationary) that the pump will not manage to achieve an acceptable volume flow (rate) even though all the other steps are intact. There will therefore be a natural limitation on how many pump stages there may be in a step based on the conditions in the well. The motors in the pump (the steps) are preferably permanent magnet motors with a stationary part attached to the diffuser and a movable part attached to the impeller. Alternatively, the motors may be an electric motor with a stationary part and a rotating part. Regardless of the motor type, all the motors will have a cavity in the centre for flow of liquid, and the rotating part of the motor is attached to the impeller for operation thereof. Alternatively, the motors may be hydraulic motors with a stationary part and a rotating part. In this case too, the motor will have a cavity in the centre for flow of liquid, and where the rotating part of the motor is attached to an impeller for operation thereof.

In addition, the pump may use bearings, preferably magnetic bearings, to take up the forces in the apparatus. A permanent magnet motor is per se highly efficient with a high efficiency factor. In addition to a more compact design, the pump has a redundancy by still being capable of delivering a pressure increase even if one or more motors (steps) come to a standstill. Each motor can, if the conditions in the well so require, be run at an individual rotational speed so as to avoid cavitation. Since the motor is no longer supplied as a long unit, but is divided into different steps, the pump handles well deviation far better than existing pumps. Service on the pump is easier as the steps are not connected to a common shaft.

According to an embodiment, the pump is characterised in that it essentially consists of permanent magnet motors which individually drive the impellers in the pump stages and that it uses magnetic bearings to take up the forces in the apparatus.

The pump according to the invention will be described with reference to the drawings, wherein:

Fig. 1 shows the principle of a plurality of steps in the pump;

Fig. 2 shows the principle of a permanent magnet motor

Fig. 3 shows a section of a permanent magnet motor;

Fig. 4 shows a section of a step including impeller, diffuser and permanent magnet motor;

Fig. 5 shows the principle of an axial permanent magnet motor;

Fig. 6 shows a section of an axial permanent magnet motor;

Fig. 7 shows a section of a step including impeller, diffuser and axial permanent magnet motor;

Fig. 8 shows a section of two steps including the principle of a bearing

arrangement;

Fig. 9 shows a section of an axially positioned motor including the principle of a bearing arrangement;

Fig. 10 shows a section of two steps with axially positioned motor including a bearing arrangement;

Fig. 1 1 is a rough outline of the connection of power;

Fig. 12 shows an embodiment where the pump is used together with a plug/packer; and

Fig. 13 shows an embodiment where the rotating part of the motor drives a shaft which in turn drives a plurality of pumps stages in a step. As shown in Fig. 4 a step (1 ) consists, as in conventional centrifugal pumps, of an impeller (2) and a diffuser (3). The number of steps (1 ) the pump consists of may vary according to the requirements of the well. Instead of a shaft, the impeller (2) is driven by a permanent magnet motor (the PM motor) (4) as shown in Fig. 2, which includes a rotating part (6) that is an integral part of the impeller (2) and a stationary part (5) that is an integral part of the diffuser (3). Fig. 13 shows an embodiment where the rotating part (6) of the motor drives a shaft (25) which in turn drives three pump stages in a step.

During mounting, the diffuser (3) is placed on the outside of the impeller (2). At the same time, the parts of the PM motor are placed in the correct position. Figure 4 shows a radially positioned PM motor (4) mounted in the impeller (2) and the diffuser (3). During operation the diffuser (3) stands still together with the stationary part of the PM motor (5). The impeller (2) is arranged so that it can rotate within the diffuser (3).

This means that when the PM motor starts to rotate, the impeller also rotates. The impeller rotates within the stationary diffuser. The method of attachment of the parts of the PM motor may vary. According to an embodiment, the rotating part of the PM motor is made of the same blank as the impeller.

The output and the capacity an impeller has to supply an increase in pressure are determined by impeller diameter and internal flow design of the impeller and diffuser. Figure 4 shows how the PM motor can be positioned without affecting the impeller diameter. The internal flow optimisation of the impeller and diffuser is not affected by the invention owing to the position of the PM motor, which means that the pump solution according to the invention can be used with known impeller and diffuser design. According to the invention, several steps can be mounted one above the other so as to enable the pumping capacity to be modified according to need. The steps are constructed with a mechanical control so that they cannot rotate in relation to one another. According to an embodiment, all steps are located within a casing. The length of the casing varies according to the number of steps used to obtain desired capacity of the system. In the bottom of the casing is a conventionally used base and at the top a head. These two are screwed into the casing so that the steps are compressed.

In conventional centrifugal pumps, the impeller is fixed to a shaft such that the radial motion is controlled. In the invention, this is done with the aid of a radial bearing (12). The position of the radial bearing may vary. Figure 8 shows a radial bearing (12) placed in the centre above the impeller (2). The radial bearing ( 12) in this case is fastened to the diffuser (3), and, during mounting, the shaft on the impeller is inserted into bearings so that the impeller is radially supported against the diffuser. Mounted in this way, the impeller is given radial support like that which other conventional centrifugal pumps with a common shaft have. In an embodiment, the radial bearing ( 12) may be of the passive magnetic bearing type, in another embodiment it may be of the active magnetic bearing type, whilst in a third embodiment it may be of the standard radial sliding bearing or roller bearing type.

The support of axial forces is effected by one axial bearing ( 1 1 ) located between the impeller in the overlying pump stage and the diffuser in the underlying pump stage, as shown in Figure 8. The position of the bearing may vary. The axial bearing is mounted in a conventionally known way. The rotating part of the bearing is mounted on the impeller. In the same way, the stationary part is mounted in the diffuser. In an embodiment, the bearing may be of the passive magnetic bearing type, whilst in another embodiment it may be of the active magnetic bearing type. This type of bearing is in theory friction-free with increased lifetime for the bearings as a result. The bearing arrangement does not preclude the use of ordinary axial sliding bearings or roller bearings. These may be of the conventional axial bearing type. In an embodiment, the motor may be of such a type that it eliminates the need for radial and axial support. The PM motor has current applied in a conventionally known way via a power cable. Redundancy is vital so that the pump does not stop if a step stops. The diffuser is constructed so that power supply is possible. Figure 1 1 shows an embodiment of power supply at the bottom left-hand side of the figure.

Figure 5 and Figure 6 show a basic drawing of an axial PM motor (7). This also consists of a rotating part (8) and a stationary part (9). This type of motor is also known in the market. Figure 7 shows an embodiment where the motor is positioned axially in a stage. The stationary part of the motor (9) is mounted in the underlying diffuser and the rotating part (8) in the overlying impeller.

According to an embodiment, the pump according to the invention is installed in the well with the aid of a remote-controlled plug or packer, as shown in Fig. 12. The plug consists of an electric motor ( 13) for setting and pulling the plug. The electric motor is, through planet gear (14), in connection with hollow shaft ( 15) that is rotated to set one or more slips ( 16) which lock the packer to the production tubing (17), and hollow shaft (18) that is rotated to set a packer element ( 19). The packer element (19) separates the inlet side from the exhaust side as shown in the figure. A hollow shaft (20) controls a ball valve (21 ). The apparatus includes pipe (22) that leads the liquid through the plug and into the pump. A valve (23) ensures that, when needed, hydraulic contact can be formed between the inlet side and the exhaust side of the pump. The valve may, for example, be a magnetic valve. The pump and the remote-controlled plug can be set together to form a unit that can be run downhole and pulled up with the aid of a cable (24).