WO2016077935A1

WO2016077935A1 - Oil well assembly for oil production and fluid injection

Info

Publication number: WO2016077935A1
Application number: PCT/CA2015/051217
Authority: WO
Inventors: Scott Craig ANDERSON; Benjamin Daniel DOHERTY
Original assignee: Opis Oil Production Integrated Systems Corp.
Priority date: 2014-11-21
Filing date: 2015-11-23
Publication date: 2016-05-26
Also published as: CA2968426A1; GB201420752D0; US20170321511A1

Abstract

An oil well assembly and a method thereof for injecting fluid into an oil reservoir to promote production of oil from the oil reservoir is provided. The oil well assembly comprises a pump for pumping oil from the oil reservoir to the surface and for transporting treatment fluid from the surface to a valve for controlling flow of treatment fluid to the oil reservoir. The pump may be lubricated using the treatment fluid even when the valve has closed the flow of treatment fluid.

Description

OIL WELL ASSEMBLY FOR OIL PRODUCTION AND FLUID

INJECTION

BACKGROUND

Field of the Disclosure

[0001] This disclosure relates to an oil well assembly and a method thereof for injecting fluid and producing oil from horizontal oil wells.

Description of Related Art

[0002] This section is intended to introduce various aspects of the art, which may be associated with the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

[0003] In the production phase of an oil well, it is often necessary to artificially lift the oil from its natural level in the wellbore to the wellhead at the surface. This lift may be accomplished using a subsurface pump, powered at or below the surface.

[0004] The oil well typically includes a casing enclosed in cement and a production tubing disposed within the casing. The casing may include perforations at the bottom end located in an oil production zone to allow crude oil to enter the well through the perforations. The top end of the well is typically sealed by a wellhead secured to the casing. The fluid in the well rises to a natural level within a well annulus between the casing and the production tubing.

[0005] Alternatively, in an open hole completion, the casing is completed above the production zone and the casing is not cemented in place across the production zone. Fluid from the production zone flows into the wellbore.

[0006] Open hole completions are commonly used in horizontal oil wells, which generally include a vertical section, a heel, and a lateral (or horizontal) section. In the horizontal oil well, the artificial lift pump is typically positioned in the vertical section and slightly below the natural fluid level.

[0007] The pump raises the pressure of the oil sufficiently to pump the oil through the production tubing to the wellhead and out of a wellhead discharge tubing. Therefore, crude oil flows from a reservoir of the oil production zone into the pump inlet, into the pump, through the production tubing, and out through the wellhead discharge tubing.

[0008] As the fluid in the vertical section gets pumped to surface (produced), the fluid level in the vertical section will drop below the natural level until the reservoir pressure is higher than the pressure induced from the fluid head in the vertical section. At this point the crude oil will flow more easily from the production zone.

[0009] Often, the viscosity of the wellbore fluids is such that the production zone will only flow around a region close to the heel section of the horizontal well. The fluid away from the heel and along the horizontal section cannot be as easily produced and delivered to the surface. Furthermore, producing a well only from the heel section can make the well susceptible to sanding off and gas plugs.

[0010] For these exemplary reasons, a production well or pump may require servicing. Servicing can be time consuming and expensive, ft is desirable to reduce servicing time and/or expense.

SUMMARY

[0011] Described is an oil well assembly for injecting fluid into an oil reservoir to promote production of oil (or other fluids and hydrocarbons) from the oil reservoir. The oil well assembly comprises a pump for pumping oil from the oil reservoir to the surface and for transporting treatment fluid from the surface to a valve for controlling flow of treatment fluid to the oil reservoir. In this way, well conditions may be improved by injecting the treatment fluid downhole through the pump, without stopping or removing the pump. The pump may be lubricated using the treatment fluid even when the valve has closed the flow of treatment fluid.

[0012] The oil well assembly may include: a production tubing for transporting oil from an oil reservoir to a surface; an injection string at least partially disposed within the production tubing for injecting treatment fluid from the surface to the oil reservoir; a pump disposed within the production tubing and in fluid communication with the injection string and comprising an outlet end and an inlet end, for pumping oil within the production tubing from the oil reservoir to the surface in a direction from the inlet end to the outlet end, and for transporting treatment fluid from the surface to the injection string in a direction from the outlet end to the inlet end; a wellhead assembly located at the surface and coupled to the production tubing for receiving oil from the production tubing, and coupled to the outlet end of the pump for providing treatment fluid to the injection string via the pump; a valve disposed within the production tubing and coupled both to the injection string and to the inlet end of the pump, for controlling an amount of treatment fluid passed from the pump to the injection string; and a port located between the inlet end of the pump and the valve, and in fluid communication with the wellhead assembly for providing treatment fluid to the pump.

[0013] The valve may be a tension regulated valve for controlling the amount of treatment fluid passed from the pump to the injection string.

[0014] The wellhead assembly may include a lift apparatus to raise and lower the pump within the production tubing and to control the opening or closing of the tension regulated valve when the pump is raised or lowered.

[0015] The pump may include a hollow rotor disposed within a housing, and the hollow rotor comprises an interior passage for passing treatment fluid from the wellhead assembly to the injection string and the port.

[0016] A process may include: providing the oil well assembly as described herein; passing treatment fluid through the pump in a direction from the outlet end to the inlet end; pumping treatment fluid with crude oil through the pump in a direction from the inlet end to the outlet end; and controlling, via a valve, an amount of treatment fluid passed from the pump to the injection string.

[0017] The foregoing has broadly outlined the features of the present disclosure so that the detailed description that follows may be better understood. Additional features will also be described herein.

BRIEF DESCRIPTION OF THE DRAWINGS

[0018] FIG. 1 is a diagram of an oil well assembly as described herein.

[0019] FIG. 2 is a cross-sectional view of a downhole section of an oil well assembly as described herein.

[0020] FIG. 3 is a diagram of a horizontal section of the oil well assembly as described herein.

[0021] FIG. 4 is a diagram of a horizontal section of the oil well assembly as described herein.

[0022] FIG. 5 is a diagram of a horizontal section of the oil well assembly as described herein.

[0023] FIG. 6 is a cross-sectional view of a pump as described herein. [0024] FIG. 7 is a cross-sectional view of a pump as described herein.

[0025] FIG. 8 is a cross-sectional view of a vertical section of the oil well assembly of FIG. 2.

[0026] FIG. 9 is a diagram of operating a valve of the oil well assembly of FIG. 2.

[0027] FIG. 10 is a diagram of a wellhead assembly of FIG. 1 controlling the operation of a valve of the oil well assembly of FIG. 2.

[0028] It should be noted that the figures are merely examples and no limitations on the scope of the present disclosure are intended thereby. Further, the figures are generally not drawn to scale, but are drafted for purposes of convenience and clarity in illustrating various aspects of the disclosure.

DETAILED DESCRIPTION

[0029] For the purpose of promoting an understanding of the principles of the disclosure, reference will now be made to the features illustrated in the drawings and specific language will be used to describe the same. It will nevertheless be understood that no limitation of the scope of the disclosure is thereby intended. Any alterations and further modifications, and any further applications of the principles of the disclosure as described herein are contemplated as would normally occur to one skilled in the art to which the disclosure relates. It will be apparent to those skilled in the relevant art that some features that are not relevant to the present disclosure may not be shown in the drawings for the sake of clarity.

[0030] These and other features, aspects and advantages of the disclosure will become apparent from the following description, appending claims and the accompanying drawings, which are briefly described below.

[0031] Figure 1 shows a diagram of an oil well assembly. In Figure 1, the wellhead assembly 20 is located at a surface of the earth and is connected to the downhole section, which is located below the surface of the earth. The wellhead assembly 20 comprises a drive mechanism 17 for turning a hollow sucker rod string 16. The hollow sucker rod string 16 extends to the downhole section and transmits torque from the drive mechanism 17 to downhole components. The hollow sucker rod string 16 may be tubing or other suitable hollow pipe. The wellhead assembly 20 seals the top of casing 10 of the downhole section. The wellhead assembly 20 comprises a feedline 19 and seal assembly 18 for injecting treatment fluid to the production zone via the downhole section. The wellhead assembly 20 comprises discharge tubing 14 to receive crude oil and other liquids produced from the production zone via the downhole section. The wellhead assembly 20 comprises a lift apparatus 15 for raising and lowering parts of the downhole section within the wellbore.

[0032] As used herein, "oil" includes liquid hydrocarbons of different viscosities, and therefore includes, for instance, light crude oil, heavy oil, and bitumen.

[0033] Figure 2 shows a cross-sectional view of a downhole section of an oil well assembly. The downhole section comprises the casing 10, a production tubing 3, the hollow sucker rod string 16, a pump 1, a valve 21, a lower rod 8 and a tail string 11. The lower rod 8 and the tail string 11 comprise an injection string which is used to deliver treatment fluid to a horizontal section of the oil well assembly located in a production zone or oil reservoir underground.

[0034] The casing 10 defines the wellbore and may be encased in cement. The area of the casing 10 located within the production zone or oil reservoir is typically perforated to allow crude oil and other hydrocarbons to flow or pass into the interior of the casing 10.

[0035] The production tubing 3 is disposed within the casing 10. An annular gap, or annulus, is formed in the space between the casing 10 and the production tubing 3. The production tubing 3 is connected to the discharge tubing 14 of the wellhead assembly 20; therefore, the production tubing 3 is used to transport the crude oil and other hydrocarbons from the oil reservoir to the surface.

[0036] The oil well may produce oil in this simplest form if the formation pressure underground is high enough to naturally force the crude oil to the surface. However, in many cases, the pressure is not high enough and artificial lift methods are required to produce the crude oil. Therefore, the oil well assembly also comprises a pump 1 disposed within the production tubing and connected to the wellhead assembly 20 via the hollow sucker rod string 16.

[0037] The pump 1 may be driven from the wellhead assembly 20 by rotation of the hollow sucker rod string 16. Alternatively, the pump 1 may be driven by a downhole motor, such as an electrical motor or a mud motor.

[0038] While the pump 1 pumps crude oil in a direction from an inlet end to an outlet end of the pump (from the oil reservoir to the surface), the pump 1 also comprises an interior passage for passing treatment fluid in an opposite direction, from the outlet end to the inlet end (from the surface to the oil reservoir). The pump 1 is in fluid communication with the injection string, which comprises the tail string 11. Therefore, in operation, the pump 1 receives treatment fluid from the wellhead assembly 20, passes the treatment fluid to the tail string 11, and the tail string 11 can inject the treatment fluid into the oil reservoir or production zone.

[0039] The oil well assembly further comprises a port (not shown in Figure 2) for lubricating the pump 1 and located between the inlet end of the pump and the valve 21. The port provides treatment fluid to the crude oil in the production tubing 3 near the inlet end of the pump. In operation, the pump 1 pumps both the crude oil and treatment fluid through the pump 1 from the inlet end to the outlet end. Therefore the treatment fluid lubricates the pump 1 when the pump 1 is pumping crude oil.

[0040] The production tubing 3 comprises a middle section 7 at which may be located various downhole tools in addition to the pump 1. For example, the oil well assembly further comprises a valve 21 disposed within the production tubing 3 and coupled both to the injection string and to the inlet end of the pump 1. The valve 21 controls the amount of treatment fluid passed from the pump 1 to the injection string.

[0041] The production tubing also comprises a lower section 12 for connecting the production tubing 3 to the tail string 11. The lower section 12 also connects to a tag bar housing 9. The tag bar housing 9 connects the top of the tail string 11 to the bottom of the production tubing 3 and defines a landing spot for a lower section of a tag bar below the valve 21. The tag bar housing 9 ensures that the bottom of the valve 21 doesn't move within the production tubing 3, allowing the valve 21 to be opened and closed as intended.

[0042] The downhole section may further comprise an upper rod 4, a tag head 5, a swivel 6, and one or more subs 23 and an aperture 25 that is located near the toe 13 of the horizontal section 22. These features will be discussed in further detail below.

[0043] The oil well assembly may improve well conditions by injecting treatment fluid downhole through the pump, without stopping or removing the pump. Preferably, the treatment fluid injection may occur simultaneously during the pumping operation, saving both time and cost during crude oil production.

[0044] For a variety of reasons, a production well or pump may require servicing. For example, an unwanted composition may be present downhole, causing reduced production or other issues. Examples of unwanted compositions include emulsions, scale, sand, wax, and paraffins. Certain compositions may block perforations in the well or stick to well tubing or rods. To inhibit such compositions, the treatment fluid may be a demulsifier, scale inhibitor, steam or heated fluids, wax inhibitor, or paraffin inhibitor. The treatment fluid may be used to mitigate a condition, for instance using a corrosion inhibitor. By bringing treatment fluid adjacent or below the pump, certain well conditions may be improved without stopping or removing the pump. The treatment fluid may be an acid or polymer.

[0045] The treatment fluid may be any suitable treatment fluid. By way of further example, the treatment fluid may be water or steam, for instance to reduce the viscosity of viscous hydrocarbons such as heavy oil or bitumen or to remove wax build up inside the well bore. Other treatment fluids may be used to otherwise treat fluids in the wellbore and/or the reservoir.

[0046] Figure 3 shows a horizontal section of an oil well assembly. The tail string

11 in the example of Figure 3 comprises a sub 23 located near the heel of the horizontal section 22. The sub 23 diverts treatment fluid to the oil reservoir near the heel of the horizontal section. The sub 23 may be pump-on or pump-off sub. A pump-on sub is normally closed until actuated, and is then opened. A pump-off sub is normally open until actuated, and is then closed.

[0047] Figure 4 shows a horizontal section of another oil well assembly. The tail string 11 in the example of Figure 4 comprises a second sub 23 located between the heel and the toe 13 of the horizontal section 22. The sub 23 diverts treatment fluid to the oil reservoir away the heel of the horizontal section.

[0048] Figure 5 shows a horizontal section of yet another oil well assembly. The tail string 11 in the example of Figure 5 comprises an aperture 25 at the toe 13 of the horizontal section 22. The aperture 25 may be one of a jet, a valve, an auger tip, a check valve, a nozzle, a sub, or a carbide tip, for discharging the treatment fluid at the toe 13.

[0049] Sanding off and gas plugs are common problems in horizontal oil wells.

Discharging treatment fluid at various locations across the horizontal section of the horizontal well may help reduce the incidence of these problems by sweeping debris away from these areas.

[0050] The setup of these subs and the number of subs that are used in the horizontal section 22 may be determined by the well conditions prior to installing the down hole assembly. For example, it is desirable to break friction along the entire horizontal section 22. This may be accomplished by injecting treatment fluid into the toe 13 of the well. However, if the well fluids are too viscous, injecting at the toe during the beginning of a treatment may force treatment fluid into the formation instead of back towards the heel and the pump. Thus, one or more pump-on subs 23 may be used to break friction along stages of the horizontal section 22, as shown in Figures 3 and 4.

[0051] Alternatively, pump-off subs 23 may be used. During oil production, the treatment fluid injection at the toe 13 causes the well fluids to flow towards the heel. If a portion of the horizontal section of well collapses, a pump-off sub may be actuated to close off treatment fluid injection from the portion of the horizontal section 22 that is downstream from the collapse. This is advantageous because it avoids having to remove the entire string in order to keep producing the well.

[0052] While the examples shown in Figures 2-5 above relate to horizontal oil wells, the present disclosure is generally applicable to any oil well, including vertical oil wells, where sand, wax and gas may present problems during crude oil production. Accordingly, the tail string 11 may be located in a vertical oil well and be used to discharge treatment fluid into the production zone of the vertical oil well.

[0053] The oil well assembly may comprise a steam assisted gravity drainage

(SAGD) system. SAGD is an enhanced oil recovery method where the treatment is an injection of high pressure steam used to heat the oil and reduce its viscosity in the well.

[0054] Figure 6 shows a cross-sectional view of a progressive cavity pump (PCP).

The PCP 1 includes a hollow rotor disposed within a stator housing for pumping fluid such as crude oil in a pumping direction within the housing. The hollow rotor includes an interior passage for passing treatment fluid therethrough in a direction opposite the pumping direction.

[0055] The PCP 1 comprises an inlet end disposed in the direction of the oil reservoir and an outlet end disposed in the direction of the wellhead assembly 20. The rotor has a corkscrew -like helical shape and the stator has a corkscrew-like helical channel on its inside surface (not shown). The rotor seals against the stator as the rotor rotates, forming a set of fixed-size cavities in between. The PCP 1 transfers fluid by means of the progress, through the pump, of the cavities, as its rotor is turned.

[0056] When the rotor is rotated, it rolls around the inside surface of the stator hole. The rotational motion of the rotor is similar to the smaller gears of a planetary gears system. As the rotor simultaneously rotates and moves around, the combined motion of the eccentrically mounted drive shaft of the rotor is in the form of a hypocycloid. In the typical case of single-helix rotor and double-helix stator, the hypocycloid is a straight line. The rotor may be driven through a set of universal joints or other mechanisms to allow for the movement.

[0057] In operation, crude oil is drawn into a cavity formed between the rotor and the stator at the inlet end. The cavity is formed by the rotation of the rotor and cavity travels from the inlet end to the outlet end as the rotor rotates. The cavity of crude oil is expelled at the outlet end of PCP 1 and crude oil is transported to the wellhead assembly 20 at the surface.

[0058] While crude oil travels in a direction from the inlet end to the outlet end, within the cavities between the rotor and the stator, treatment fluid travels in an opposite direction from the outlet end to the inlet end within an interior passage of the hollow rotor.

[0059] Specific designs of PCPs involve the rotor being made of steel, coated with a smooth hard surface, for instance chromium, with the stator made of a molded elastomer inside a metal tube body. The elastomer core of the stator forms the complex cavities. The rotor may be held against the inside surface of the stator by angled link arms, bearings (immersed in the fluid) allowing it to roll around the inner surface.

[0060] In the example of Figure 6, the hollow rotor further comprises a port 28 located below the inlet end of the PCP 1; thus, the port 28 is positioned in the production tubing 3 between the inlet end of the PCP 1 and the valve 21. The PCP 1 passes treatment fluid from the interior passage to the port 28 to discharge the treatment fluid into inlet end of the PCP 1. The treatment fluid is then pumped through the PCP 1 from the inlet end to the outlet end. Accordingly, the PCP 1 of the present disclosure may require less servicing than PCPs in conventional oil well assemblies. For instance, friction between the rotor and stator of the PCP 1 or abrasive particles may degrade the rotor or stator. While the pumping fluid (e.g. crude oil) can provide lubrication to the PCP 1, this is not always sufficient. Therefore, if the pump is run dry, such as when gas is lifted through the pump (known as a gas kick), the friction in the pump may become high enough to damage the PCP 1. The treatment fluid may include a pump lubricant. Injecting the pump lubricant below or adjacent the PCP 1 allows the pump lubricant to pass through the PCP 1.

[0061] Figure 7 shows a cross-sectional view of a PCP combined with a capillary string for providing treatment fluid to the PCP. The PCP of Figure 7 operates similarly to the PCP of Figure 6; however, in Figure 7 a second port is located at the end of a capillary string 27 and positioned in the production tubing 3 between the inlet end of the PCP 1 and the valve 21. While the PCP 1 passes treatment fluid from the interior passage to the injection string, the capillary string 27 separately discharges the treatment fluid into inlet end of the PCP 1. The treatment fluid is then pumped through the PCP 1 from the inlet end to the outlet end. Figure 7 shows an example where it may be preferable to supplement the port 28 on the rotor with the port of the capillary string 27. If the injected treatment fluid has sand or debris in it that could plug the port 28, the capillary string 27 will still be able lubricate the PCP 1.

[0062] Although Figures 6 and 7 show examples using a PCP, any suitable pump may be used. In general, the pump may be a positive displacement pump. Positive displacement pumps make a fluid move by trapping a fixed volume of fluid and forcing that trapped volume downstream. Examples of positive displacement pumps include screw pumps and PCPs as described above.

[0063] The pump may also be a kinetic-energy pump, for instance a centrifugal pump. A centrifugal pump includes a rotor with impeller blades and works by converting rotational kinetic energy to hydrodynamic energy of the fluid. Centrifugal pumps are commonly used in oil production. Since they are commonly electrically powered, they are often referred to as Electrical Submersible Pumps (ESPs). An ESP system may include surface components and subsurface components. Surface components may include the motor controller, surface cables, and transformers. Subsurface components may include the pump, motor, seal and cables. The pump itself is a multi-stage unit with the number of stages being determined by the operating requirements. Each stage may include a driven impeller and a diffuser which directs flow to the next stage of the pump. An ESP system may include a number of components that turn a staged series of centrifugal pumps to increase the pressure of the well fluid and push it to the surface.

[0064] The pump may also be powered by a fluid drive system. The treatment fluid that is being pumped down through the hollow sucker rod string can be used to turn a remote section of the tubing string similar to a mud motor that is commonly used in oil well drilling. The fluid drive system could use produced water from either an onsite satellite or an existing injection facility to pump water down the rod string, through the mud motor, to drive the rotor. The use of a fluid drive system and a mud motor reduces friction and wear on the rod string.

[0065] Figure 8 shows a cross-sectional view of a vertical section of the oil well assembly of Figure 2. The vertical section comprises the pump 1, connected to the tag head 5 via the upper rod 4. The tag head 5 is connected to the swivel 6, which is in turn connected to the valve 21. The valve is connected to the injection string, which comprises the lower rod 8 connected to the tail string (not shown).

[0066] The tag head 5 can be disconnected from the rotor and allows the rotor to be removed from the oil well assembly. During this operation, the tag head 5 is locked in the vertical section and secured to the valve 21 and other downhole components. Thus, the downhole components do not need to be removed when the rotor is removed.

[0067] The swivel 6 couples the pump 1 to the valve 21 in order to provide passage of treatment fluid between the interior passage and the value. The swivel 6 also decouples rotational movement between the pump 1 and the valve 21 in order to allow the hollow rotor to rotate while the valve 21 remains stationary.

[0068] Figure 9 shows a method of operating the valve of the oil well assembly of

Figure 2. In Figure 9, the valve 21 is a tension regulated valve. The flow of the valve 21 is controlled by opening and closing the valve. Specifically, a top end of the valve is connected to the swivel 6 and a bottom end of the valve is connected to the lower rod 8. The bottom end of the valve and the lower rod 8 are stationary while the top end of the valve and the swivel can be moved in a vertical direction along the axis of the wellbore.

[0069] When the top end of the valve is raised, the valve opens to allow more flow of treatment fluid from the wellhead assembly 20 to the tail string 11. When the top end of the valve is lowered, the valve closes to restrict the flow of treatment fluid from the wellhead assembly 20 to the tail string 11. Fully closing the valve may completely shut off flow of treatment fluid.

[0070] Figure 10 is a method of operating the wellhead assembly of Figure 1 to control the valve of Figures 2 and 9. The wellhead assembly 20 comprises a lift apparatus 15 for raising and lowering components of the oil well assembly. The lift apparatus 15 is connected to the hollow sucker rod string 16 which is in turn connected to the pump 1, the upper rod 4, the tag head 5, the swivel 6, and the top end of the valve 21. Therefore, the lift apparatus 15 can raise the downhole components coupled to the top end of the valve 21 in order to open the valve 21. The lift apparatus 15 may also lower the downhole components coupled to the top end of the valve 21 in order to close the valve 21. According to Figure 10, the wellhead assembly 20 may thus be configured to control the flow of the treatment fluid through the valve 21.

[0071] In the preceding examples, the operation of the valve 21 does not affect the flow of treatment fluid to the inlet end of the pump 1. In particular, while the valve 21 may shut off the flow of treatment fluid from the tail string, the port 28 or the capillary string 27 will deliver treatment fluid to the inlet end in order to lubricate the pump 1.

[0072] According to the present disclosure, the oil well assembly may reduce the time and cost of performing routine maintenance. Furthermore, the routine maintenance may be more easily automated. An automated system helps reduce the likelihood of burning out the pump as the pump can be continuously lubricated or lubricated according to a schedule. An automated system makes it possible to deal with multiple well conditions. For example, the automated system can be programed for scheduled hot water/chemical treatments to deal with wax. The system can also be programmed to conduct a sand cleanout. After a sufficient volume of hot water/chemical has been pumped to clean off the wax, the system can pick up the pump rate on both the injection pump and the stator pump to create lift off bottom, ensuring the production formation remains clean and clear keeping production loss to a minimum and service cost low or non-existent.

[0073] Alternatively, the maintenance may be performed manually in response to deteriorating oil well conditions. Even according to the manual maintenance method, the present oil well assembly benefits crude oil production by reducing production loss. In particular, the present oil well assembly reduces the need to bring in a rig or a well site supervisor because the maintenance can be completed without removing the well head.

[0074] Therefore, the system and method advantageously provides the ability for maintenance of the oil well to be controlled remotely by office personnel, for example. Consequently, the system and method may in some cases replace or automate the role of the field personnel, the well site supervisor, the operator, the rig manager, and the safety hand.

[0075] It should be understood that numerous changes, modifications, and alternatives to the preceding disclosure can be made without departing from the scope of the disclosure. The preceding description, therefore, is not meant to limit the scope of the disclosure. Rather, the scope of the disclosure is to be determined only by the appended claims and their equivalents. It is also contemplated that structures and features in the present examples can be altered, rearranged, substituted, deleted, duplicated, combined, or added to each other.

Claims

CLAIMS:

1. An oil well assembly comprising:

a production tubing for transporting oil from an oil reservoir to a surface;

an injection string at least partially disposed within the production tubing for injecting treatment fluid from the surface to the oil reservoir;

a pump disposed within the production tubing and in fluid communication with the injection string and comprising an outlet end and an inlet end, for pumping oil within the production tubing from the oil reservoir to the surface in a direction from the inlet end to the outlet end, and for transporting treatment fluid from the surface to the injection string in a direction from the outlet end to the inlet end;

a wellhead assembly located at the surface and coupled to the production tubing for receiving oil from the production tubing, and coupled to the outlet end of the pump for providing treatment fluid to the injection string via the pump;

a valve disposed within the production tubing and coupled both to the injection string and to the inlet end of the pump, for controlling an amount of treatment fluid passed from the pump to the injection string; and

a port located between the inlet end of the pump and the valve, and in fluid communication with the wellhead assembly for providing treatment fluid to the pump.

2. The oil well assembly of claim 1, wherein the valve is a tension regulated valve for controlling the amount of treatment fluid passed from the pump to the injection string.

3. The oil well assembly of claim 2, wherein the wellhead assembly comprises a lift apparatus to raise and lower the pump within the production tubing and to control the opening or closing of the tension regulated valve when the pump is raised or lowered.

4. The oil well assembly of claim 1, wherein the pump comprises a hollow rotor disposed within a housing, and the hollow rotor comprises an interior passage for passing treatment fluid from the wellhead assembly to the injection string and the port.

5. The oil well assembly of claim 4, wherein the treatment fluid provided from the port is pumped with the oil within the production tubing from the inlet end to the outlet end for lubricating the pump.

6. The oil well assembly of claim 5, wherein the port is located on the inlet end of the hollow rotor.

7. The oil well assembly of claim 6, wherein a second port is located at an end of a capillary string, the capillary string disposed within the production tubing between the wellhead assembly and the pump.

8. The oil well assembly of claim 4, further comprising a swivel for coupling the pump to the valve in order to provide passage of treatment fluid between the interior passage and the value, and for decoupling rotational movement between the pump and the valve in order to allow the hollow rotor to rotate while the valve remains stationary.

9. The oil well assembly of claim 4, further comprising a tag head for releasably coupling the pump to the valve in order to allow the hollow rotor to be disconnected and removed from the oil well assembly without removing the valve and the injection string.

10. The oil well assembly of claim 4, wherein the pump is a progressive cavity pump.

11. The oil well assembly of claim 4, wherein the pump is a screw pump.

12. The oil well assembly of claim 4, wherein the pump is a positive displacement pump.

13. The oil well assembly of claim 4, wherein the pump is a kinetic-energy pump.

14. The oil well assembly of claim 4, wherein the pump is a centrifugal pump.

15. The oil well assembly of claim 1, wherein the injection string comprises a tail string located at a bottom end of the production tubing, the tail string comprising a horizontal section for injecting treatment fluid at horizontally spaced apart regions of the oil reservoir.

16. The oil well assembly of claim 15, wherein the tail string comprises a sub near a heel of the horizontal section for discharging the treatment fluid near the heel.

17. The oil well assembly of claim 15, wherein the tail string comprises a sub between a heel of the horizontal section and a toe of the horizontal section for discharging the treatment fluid away from the heel.

18. The oil well assembly of claim 15, wherein the tail string comprises a toe comprising one of a jet, a valve, an auger tip, a check valve, a nozzle, a sub, or a carbide tip, for discharging the treatment fluid at the toe.

19. The oil well assembly of claim 1, further comprising a hollow sucker rod string for coupling the wellhead to the pump in order to drive the pump from a drive mechanism of the wellhead assembly and to transport treatment fluid to the pump from the wellhead assembly.

20. A process comprising:

a) providing the oil well assembly of any one of claims 1 to 17;

b) passing treatment fluid through the pump in a direction from the outlet end to the inlet end;

c) pumping treatment fluid with crude oil through the pump in a direction from the inlet end to the outlet end; and

d) controlling, via a valve, an amount of treatment fluid passed from the pump to the injection string.

21. The process of claim 20, wherein the treatment fluid comprises a corrosion inhibitor, a demulsifier, a scale inhibitor, a wax inhibitor, a paraffin inhibitor, or a pump lubricant.

The process of claim 20, wherein the treatment fluid comprises water or steam.