WO2015063133A1

WO2015063133A1 - Valve and method for injecting treatment fluid in a wellbore

Info

Publication number: WO2015063133A1
Application number: PCT/EP2014/073193
Authority: WO
Inventors: Lubbertus Lugtmeier
Original assignee: Shell Internationale Research Maatschappij B.V.; Shell Oil Company
Priority date: 2013-10-31
Filing date: 2014-10-29
Publication date: 2015-05-07
Also published as: AU2014101597A4; CN205876267U; AU2014343829A2

Abstract

The present invention provides a valve and method for injecting a treatment fluid in a wellbore. The valve comprises a cylinder comprising a fluid inlet, at least one lateral fluid outlet, and an internal bore providing a fluid passage from the fluid inlet towards the fluid outlet. A piston member is moveably arranged within the internal bore, being movable between a closed position and an open position, wherein in the closed position the piston member blocks fluid flow from the fluid inlet towards the fluid outlet, and wherein in the open position the piston member allows fluid flow from the fluid inlet to the fluid outlet. The piston may be spring energized. A labyrinth seal section is provided for sealing an annular space between the piston member and an inner surface of the cylinder, the labyrinth seal section comprising a number of circumferential grooves.

Description

VALVE AND METHOD FOR INJECTING TREATMENT FLUID IN A

WELLBORE

The invention relates to a valve and a method for injecting treatment fluid in a borehole. The borehole is for instance a wellbore for the production of

hydrocarbons .

At a first stage of hydrocarbon production, also referred to as primary recovery, the reservoir pressure is considerably higher than the bottomhole pressure inside the wellbore. This high natural pressure

differential drives hydrocarbons toward the wellbore and up to surface. To reduce the bottomhole pressure or increase the pressure differential to increase

hydrocarbon production, an artificial lift system may be used. The primary recovery stage reaches its limit when the reservoir pressure has decreased to a level whereat the production rates are no longer economical. During primary recovery, only a relatively small percentage of the initial hydrocarbons in place are produced. For example around 10 to 20% for oil or gas reservoirs.

A second stage of hydrocarbon production is referred to as secondary recovery, during which an external fluid such as water or gas is injected into the reservoir through one or more injection wells which are in fluid communication with the production well. Thus, the reservoir pressure can be maintained at a higher level for a longer period and the hydrocarbons can be displaced towards the wellbore. The secondary recovery stage reaches its limit when the injected fluid is produced in considerable amounts from the production wells and the production is no longer economical. The successive use of primary recovery and secondary recovery in a gas

reservoir may produce for instance about 30 to 45% of the oil or gas in place .

Enhanced Oil Recovery (EOR) or Enhanced Gas Recovery refers to techniques for increasing the amount of hydrocarbons which can be extracted from the reservoir. Enhanced Oil Recovery or Enhanced Gas Recovery is sometimes referred to as tertiary recovery as it is typically carried out after secondary recovery, but it can be initiated at any time during the production life of the hydrocarbon reservoir. Enhanced Oil Recovery or Enhanced Gas Recovery may be achieved by injecting a treatment fluid into the hydrocarbon production wellbore.

When natural gas flows to the surface in a producing gas well, the gas carries liquids to the surface if the velocity of the gas is high enough. A high gas velocity results in a mist flow pattern in which liquids are finely dispersed in the gas. Consequently, a low volume of liquid is present in the tubing or production conduit, resulting in a pressure drop caused by gravity acting on the flowing fluids. As the gas velocity in the production tubing drops with time, the velocity of the liquids carried by the gas declines even faster. Flow patterns of liquids on the walls of the conduit cause liquid to accumulate in the bottom of the well, which can either slow or stop gas production altogether.

Possible solutions to this problem include the installation of a velocity string, a capillary string injecting foamers, or a pump to continuously or

intermittently pump the water to the surface to remove the hydrostatic barrier that the water creates. A common practice is to use a device called a plunger to lift the liquids. Improved electrical pumps coming onto the market may enhance the effectiveness of the technology.

The same concept is also applicable to oil wells when they are at the end stage of production. In this case, the reservoir pressure drops to such a low level that it cannot lift the weight of the oil/water column to the surface. By injecting a gas (such as nitrogen) into the wellbore at a specific point, the density of the fluid column can be reduced to the point that the reservoir pressure is once again able to lift fluids to the surface .

As many hydrocarbon production wellbores are nowadays near the end of their secondary recovery production life or have already passed the secondary recovery stage, Enhanced Oil Recovery or Enhanced Gas Recovery is becoming increasingly important to maintain the

production capacity and extend the production life of the well. Consequently, it is more often desirable to inject a treatment fluid or foam into the wellbore.

Liquid loading in gas wells currently affects a capacity of approximately 3.5 MMm³/day of gas production in the Netherlands alone. Along with other solutions, chemical foamers are currently being applied to combat this problem. Foam is being applied in batch mode or in a continuous mode.

A foam reservoir and pump are located at surface level. The pump is volume-controlled and exactly doses the foam. A capillary, a narrow tube having an outer diameter of for instance 1/4", runs down the production tubing to the bottom of the wellbore. Gas wells may typically deviate from vertical. Hence, there are two lengths regarding the capillary. The Along Hole Depth (AHD) is the absolute length of the capillary, while the True Vertical Depth (TVD) is the vertical depth relative to surface. On a deviated wellbore, the TVD is always less than the AHD .

The flowing bottom hole pressure (FBHP) of a liquid- loading wellbore is typically between 10 and 100 bar. The liquid in the capillary creates a liquid column providing a certain pressure corresponding to the depth (TVD) of the wellbore. In a wellbore of 3 km TVD, the pressure of the liquid column at the downhole end of the capillary may be in the order of 300 bar. This pressure can be much higher for deeper wellbores. The capillary may be rated, for instance, for 10.000 psi (690 bar) . A pressure regulating valve is applied at the downhole end of the capillary. Without this valve, the liquid column would cause the pressure in the capillary just beyond the pump to decrease below the evaporation pressure of the foamer if the pump would shut down. The foamer would than evaporate, leaving a solid residue of chemicals, which may block the capillary.

Many wellbores are provided with a surface controlled sub surface safety valve (SC-SSSV) . The capability to retain the SC-SSSV functionality while maintaining foamer injection through a capillary string required the development of new equipment as well as the modification of existing equipment.

One option is a method, developed by the applicant, using the existing SC-SSSV hydraulic control system also for fluid injection. This method involves modifying the safety valve equipment accordingly and use it for foam injection. For offshore use, the applicant developed a similar method. Both methods require one or two chemical back pressure valves. The current experience with permanently installed fluid injection strings shows that the required Back Pressure Valve assembly is often the weakest link in the entire system and requires regular, and very expensive, change out operations. As many operations, both onshore and offshore, will install many more chemical injection strings in the future, it is key that the Back Pressure Valve assembly works flawless during a set time interval. The set time interval may be at least 2 years of operation, but is preferably longer, if possible the remaining life cycle of the well.

Aside from the fact that a well entry to change out the Back Pressure Valve is a high risk operation with respect to possible harm to both people and environment, it also generates minimum operational costs, for instance at least EUR 30,000 Euro (onshore) and EUR 150,000

(offshore) . During the change out operation, there is also a high potential risk of losing equipment, which would require a very costly additional fishing operation.

Typically, the average change out frequency is about six months. Depending on the installed system and the failure mechanism, costs related to a well which is not in production (deferment) are in general relatively high. To make the permanently installed foam injection system cost effective, the average change out frequency is preferably in the order of two years or more.

Therefore, the design of a reliable Back Pressure Valve is key for future flawless delivery of gas (and oil) production from liquid-loaded wells.

WO 2005/045183 describes a method and system for injecting a treatment fluid into a well. The well may comprise a surface controlled subsurface safety valve (SC-SSV) which is mounted in a production tubing of the wellbore. The safety valve is typically controlled by varying fluid pressure in a valve control conduit which extends from a wellhead to the SC-SSV through an annular space between the production tubing and a wellbore casing. A treatment fluid injection conduit is connected to the valve control conduit and is suspended downwardly within the production tubing from the safety valve to a production zone of the well. The treatment fluid

injection conduit may be a steel conduit having an outer diameter which is less than a centimetre and a length enabling the conduit to reach the production zone. The length is, for example, 1 to 3 km.

In practise, the treatment fluid injection conduit has a treatment fluid injection valve at its lower end. The treatment fluid injection valve is generally a ball and seat valve. As the treatment fluid injection valve is situated at a considerable depth below the surface, it can be subjected to a high working pressure, for example 100-300 bar, sometimes even up to 400 to 500 bar or more. At such a high working pressure, the treatment fluid injection valve has to be displaceable between a closed position and an open position to accurately meter the injection of the treatment fluid into the production zone. In addition, the treatment fluid usually contains chemicals, such as a foam generating agent, which may lead to fouling and corrosion of the treatment fluid injection valve. This increases the risk of failures, such as blockage, and may thus negatively affect the reliability of the treatment fluid injection valve.

US-2010/0096127 discloses a constant flow valve comprising a fixed sleeve having an inlet, a fixed port formed through a side of the fixed sleeve, a floating sleeve coaxial and slidable with respect to the fixed sleeve, a floating port formed through a side of the floating sleeve and selectively registerable with the fixed port, a restriction orifice on an end of the floating sleeve in fluid communication with the floating port, and a compressible spring in contact with the restriction orifice on a side of the restriction orifice opposite the fixed sleeve. When injection fluid is directed to the inlet, the fluid flows to the fixed sleeve, through the registered fixed and floating ports, and through the restriction orifice to generate a pressure differential across the restriction orifice that creates a force to slide the floating sleeve away from the fixed sleeve. As a result the floating port and fixed port misalign which in turn reduces the flow area through the flow control device. The reduced flow area reduces flow through the ports that in turn decreases the pressure differential across the restriction orifice. When the pressure drop across the restriction orifice and the spring force are substantially the same the floating orifice will stabilize and cease to move, thereby maintaining a constant flow rate of fluid.

The constant flow valve of US-2010/0096127 is designed for a predetermined flow rate of fluid, for instance by selecting a certain spring force. It is impossible to adjust the flow rate to a lower rate, only to stop the flow. In addition, the sliding sleeve, and especially the annulus thereof and the aligning openings, are prone to fouling and blocking. The latter increases risk of failures and negatively affects the reliability of the valve. For the harsh environment downhole, this valve has proven to be too unreliable.

WO-2013/004609 discloses a foam injection valve comprising a piston which is moveable within a housing. The housing is provided with a lateral opening.

Despite the available prior art systems for foam injection as described above, in practice it has proved difficult to manufacture valves having adequate

reliability, robustness and/or lifetime. Reference is made again to the harsh downhole conditions. In practice, control of the valve to inject adequate amounts of foam in the well may be frequently hampered by leaking seals or blocked valves.

It is an object of the present invention to provide an improved injection valve and method for injecting a treatment fluid into a wellbore.

The invention thereto provides an injection valve for injecting treatment fluid in a wellbore, comprising:

- a cylinder comprising a fluid inlet, at least one lateral fluid outlet, and an internal bore providing a fluid passage from the fluid inlet towards the fluid outlet ;

- a piston member being moveably arranged within the internal bore between a closed position and an open position, wherein in the closed position the piston member blocks fluid flow from the fluid inlet towards the fluid outlet, and wherein in the open position the piston member allows fluid flow from the fluid inlet to the fluid outlet; and

- a labyrinth seal section for sealing an annular space between the piston member and an inner surface of the cylinder at least between the fluid inlet and the fluid outlet, the labyrinth seal section comprising a number of circumferential grooves .

With the treatment fluid injection valve according to the invention, the closed position and the (fully) open position are defined by the movement of the piston member within the cylinder. The cylinder is stationary, and may be arranged within the protective housing. In the closed position, the piston member blocks the flow path from the axial fluid passage in the tubular housing toward the axial fluid passage of the sleeve member so that the treatment fluid injection valve is closed. Even at the relatively high pressures, and pressure differentials when injection fluids in the wellbore, which may exceed 200 to 300 bar, the leak rate of the valve of the invention may be zero, or at least relatively low. The leak rate may remain zero to very low even when the treatment fluid injection valve is injecting fluid at high working pressures. The specific construction of the injection valve according to the invention prevents fouling and corrosion, and therefore significantly extends the lifetime of the injection valve. Consequently the valve can withstand the influence of chemical treatment fluid, has an increased lifespan, and

maintenance can be limited. The treatment fluid injection valve of the invention is reliable due to reduced risks of failure. Typically, the valve can be designed to operate continuously with a chemical treatment fluid for an extended period of, for example, two years or more without failure .

In an embodiment, the circumferential grooves of the labyrinth seal section are arranged on the outer surface of the piston. The labyrinth seal section may comprise at least five to ten grooves. The labyrinth seal section may extend at least over a length between the fluid inlet and the fluid outlet. In an improved embodiment, the labyrinth seal section extends beyond the fluid outlet. A length of the labyrinth seal section beyond the fluid outlet may be at least equal to, or greater than, the length of the labyrinth seal section between the fluid outlet and a static seal.

In a preferred embodiment, in the closed position the axial end surface of the piston member abuts against a seat which is made of a resilient material. The seat is situated, for example, adjacent to an axial end of the cylinder .

When the piston member is in the closed position, the end of the piston engages the seat made of the resilient material. The resilient material may comprise, for example rubber. The engagement between the end surface and the resilient seat guarantees that the treatment fluid injection valve is closed off without any leaks. The sealing member provided radially around the piston member reduces wear of the seat. When the valve is in the open position, there is no, or hardly any, pressure difference across the resilient seal. The dynamic sealing (the piston, and optionally the sealing member) and static sealing (the resilient seat) are separated from each other. The static seal ensures proper sealing in static, closed position, limiting or obviating fluid leakage. The tougher sealing member provides sealing in a dynamic condition. Thus, the valve of the invention combines low to absent fluid leakage with relatively long lifespan of the resilient seal.

In an embodiment, the at least one lateral fluid opening in the sleeve member defines an adjustable flow area, wherein the adjustable flow area are can be adjusted by controlling the position of the piston member between the closed position and the open position. It is also possible for the piston member to be controlled to at least one partially open position between the closed position and the (fully) open position, and wherein, with the piston member in the open position, the at least one lateral fluid opening in the sleeve member defines a first flow area, and wherein, with the piston member in its at least one partially open position, the at least one lateral fluid opening in the sleeve member defines a second flow area which is smaller than the first flow area .

With the piston member in the open position, the lateral fluid opening in the sleeve member defines a flow area corresponding to a predetermined maximum volume flow. In a partially open position, the lateral fluid opening in the sleeve member defines a respective flow area which is smaller than the flow area corresponding to the predetermined maximum volume flow. The piston member can be displaced from the closed position to the

partially open position ("throttling position") by controlling the pressure of the treatment fluid in the sleeve axial fluid passage. Thus, the flow area defined by the lateral fluid opening in the sleeve member can be adjusted by displacing the piston member, and thus the treatment fluid injection valve can be operated to deliver metered amounts of treatment fluid from the treatment fluid injection conduit to the production zone of the hydrocarbon production well. In other words, it is possible to accurately meter the amount of injected treatment fluid. For example, the treatment fluid injection valve may be configured to inject 1 to 5 litres per hour or per day.

In addition, when the treatment fluid is a chemical, for example a foaming agent, it may form a deposit on the edges of the lateral fluid opening, which causes a risk of blocking. According to this embodiment, the flow area defined by the lateral fluid opening in the sleeve member can be increased by the operation of the piston member so as to wash away any residuals which may have set onto the lateral fluid opening during use. Thus, the lateral fluid opening can be periodically cleaned by temporarily increasing the volume flow through the lateral fluid opening. This results in a treatment fluid injection valve having excellent reliability.

The at least one lateral fluid opening of the sleeve member may comprise a single lateral fluid opening or a plurality of lateral fluid openings. In a particular embodiment, the sleeve member comprises at least a first lateral fluid opening and at least a second lateral fluid opening which is arranged at an axial distance from the first lateral opening, wherein the piston member can be moved incrementally from the closed position to a first partially open position and from the first partially open position to a second partially open position, wherein the piston member in its first partially open position permits treatment fluid flow through the first lateral fluid opening in the sleeve member and blocks treatment fluid flow from the axial fluid passage of the sleeve member toward the second lateral fluid opening of the sleeve member, and wherein the piston member in its second partially open position permits treatment fluid flow through the first and second lateral fluid openings in the sleeve member.

When the piston member is displaced from the closed position over an incremental distance to the first partially open position, treatment fluid is allowed to flow through the flow path from the fluid inlet through the axial fluid passage in the tubular housing, the axial fluid passage of the sleeve member, and the first lateral fluid opening in the sleeve member toward the lateral fluid outlet in the tubular housing. At the same time, the piston member, in particular its sealing member, prevents treatment fluid from flowing from the fluid inlet through the axial fluid passage in the tubular housing, the axial fluid passage in the sleeve member and into the second lateral fluid opening. Thus, the

treatment fluid injection valve is operated to inject a metered volume of treatment fluid corresponding to the first lateral fluid opening.

From the first partially open position, the piston member may be displaced over a further incremental distance to the second partially open position, wherein treatment fluid is allowed to flow through the first and second lateral fluid opening in the sleeve member toward the lateral fluid outlet in the tubular housing. As a result, the metered amount of treatment fluid is

increased. It should be noted that the sleeve member may comprise further lateral fluid openings which are arranged at an axial distance from each other and accordingly further partially open positions of the piston member. In the second partially open position, the piston member blocks treatment fluid flow from the axial fluid passage in the sleeve member toward the further lateral openings.

It is possible for the treatment fluid injection valve to comprise a spring member which biases the piston member to the closed position. The spring provides a bias force upon the piston member for returning the piston member toward the closed position. The bias force can be overcome by the pressure of treatment fluid flowing into the axial fluid passage in the tubular housing and acting onto the pressure-receiving axial end surface of the piston member. When the pressure is increased within the treatment fluid injection conduit, it bears upon the pressure-receiving end surface of the piston member to urge the piston member to move axially with respect to the sleeve member in the direction toward the open position, and the spring member is compressed by the piston member. For example, the spring member comprises a compression spring which is arranged under pretension between the piston member and a setting screw which is received into the tubular housing.

In an embodiment, the cylinder is removably arranged within a protective housing. Thus, the cylinder can be easily replaced. According to another aspect, the invention provides a wellbore provided with an injection valve as disclosed above .

According to another aspect, the invention provide a method for injecting fluid in a wellbore, using an injection valve as disclosed above.

In an embodiment, the wellbore may be provided with a sub-surface safety valve and with at least one injection valve. The method may comprise the steps of:

- introducing a sub-surface safety valve in the wellbore ;

- providing a hydraulic control line for controlling the sub-surface safety valve;

- providing at least one injection valve according to claim 1 in a section of the hydraulic control line extending below the sub-surface safety valve; and

- controlling the fluid pressure in the hydraulic control line to control the sub-surface safety valve and the at least one injection valve.

In an embodiment, the step of controlling the fluid pressure comprises :

i) controlling the fluid pressure in a first pressure range between 0 and a first threshold pressure, wherein the sub-surface safety valve and the at least one injection valve are closed;

ii) controlling the fluid pressure in a second pressure range between the first threshold pressure and a second threshold pressure, wherein the sub-surface safety valve is open and the at least one injection valve is closed; and

iii) controlling the fluid pressure in a third pressure range exceeding the second threshold pressure, wherein the sub-surface safety valve and the at least one injection valve is open. The treatment fluid injection valve according to the invention may comprise any of the features described in the claims and the description above, either individually or in any combination of features .

The invention will now be explained, merely by way of example, with reference to the accompanying drawings, wherein :

Figure 1 shows a cross-sectional view of an exemplary hydrocarbon production well provided with a system for injecting a treatment fluid in accordance with the present invention;

Figure 2a shows a cross-sectional view of a treatment fluid injection valve of the system for injecting a treatment fluid shown in figure 1, wherein the treatment fluid injection valve is in a closed position;

Figure 2b shows a cross-sectional view of the treatment fluid injection valve shown in figure 2a, wherein the treatment fluid injection valve is in a partially open position ("throttling position");

Figure 2c shows a cross-sectional view of the treatment fluid injection valve shown in figure 2a, wherein the treatment fluid injection valve is in an open position ;

Figure 3 shows a cross-sectional view of a sealing member for sealing the piston member with respect to the sleeve member of the treatment fluid injection valve shown in figure 2a;

Figures 4a, 4b, 4c, 4d show cross-sectional views of exemplary embodiments of sleeve members, including one or more lateral openings, which can be used with the treatment fluid injection valve shown in figure 2a;

Figure 5 shows a cross section of another embodiment of the valve of the present invention; Figure 6 shows a perspective view of an embodiment of a cylinder member for the valve of the present invention;

Figure 7 shows a cross section of an embodiment of a static seal of the valve of the invention;

Figure 8 shows a detail of the static seal of Figure

7;

Figure 9 shows a cross section of yet another embodiment of te valve of the present invention;

Figure 10 shows a perspective view of an embodiment of a piston for the valve of Fig. 9;

Figure 11 shows a detail in cross-section of the piston for the valve of Fig. 9;

Figure 12 shows a cross section of an embodiment of the valve of the invention in a closed state;

Figure 13 shows a cross section of the embodiment of the valve of Figure 12 in a (partially) open state;

Figure 14 shows a graph, indicating exemplary test results of an embodiment of the valve of the invention, indicating differential pressure across the valve in time; and

Figure 15 shows another graph, indicating exemplary test results of an embodiment of the valve of the invention .

Figure 1 schematically shows a wellbore 1 according to the invention. The wellbore 1 comprises a borehole 4 which has been drilled from the surface 3 through a number of earth formations 5, 6, 7, 8 up to a production formation 9. The production formation 9 comprises hydrocarbons, for example oil and/or gas. The wellbore 4 is lined with casings 12 and a liner 15 which is

suspended from the lowermost casing 12 by means of a liner hanger 13. The liner 15 extends from the lowermost casing 12 to the production formation 9 and comprises perforations 11 for allowing fluid communication from the production formation 9 to a production zone 10 of the hydrocarbon production well 1.

A production tubing 14 is disposed within the casings 12 and the liner 15 of the wellbore 4. The production tubing 14 may be constructed in various ways. For example, the production tubing 14 comprises sections of standard production tubing which are connected together by threads. The production tubing 14 extends from a wellhead 2 of the hydrocarbon production well 1 to the production zone 10. Production fluids, such as oil and/or gas, may be conveyed to the wellhead 2 at the surface 3 through the interior of the production tubing 14. A Christmas tree 16 is installed on the wellhead 2 so as to control fluid flow in and out of the wellbore 4.

A downhole safety valve 17 is installed within the production tubing 14. In this exemplary embodiment, the downhole safety valve 17 is constructed as a surface- controlled subsurface safety valve. The safety valve 17 may be situated at a depth greater than 50 m, for example at approximately 100 m. The safety valve 17 provides emergency closure of the production tubing 14 in the event of an emergency. The safety valve 17 is designed to be fail-safe, i.e. the wellbore 4 is isolated in the event of failure or damage to the surface production control equipment. An annular space 25 is defined between the outer radial surface of the production tubing 14 and the casings 12. A hydraulic control line 18 extends from the surface 3 within the annular space 25 to the safety valve 17 so as to control the safety valve.

A packer member 24 is arranged between the production tubing 14 and the liner 15 so as to secure in place a lower portion of the production tubing 14 and to

substantially isolate the annular space 25 from the interior of the production tubing 14. For example, the packer member 24 comprises a means for securing the packer member 24 against the wall of the liner 15, such as a slip arrangement, and a means for establishing a reliable hydraulic seal to isolate the annular space 25, typically by means of an expandable elastomeric element.

The portion of the production tubing 14 below the packer member 24 is generally referred to as the tail.

The hydrocarbon production well 1 according to the invention comprises a system for injecting a treatment fluid into the production zone 10. The system for injecting a treatment fluid into the production zone 10 comprises a treatment fluid injection conduit 19 having an upper supply end 20 and a lower discharge end 21. In this exemplary embodiment, the upper supply end 20 is installed in the Christmas tree 16.

The treatment fluid injection conduit 19 is arranged in the interior of the production tubing 14 to the safety valve 17. The treatment fluid injection conduit 19 may extend through the safety valve 17 and runs further downward through the interior of the production tubing 14 up to the lower discharge end 21 in the production zone 10. Thus, the treatment fluid injection conduit 19 may extend below below the safety valve 17 and below the packer member 24. The treatment fluid injection conduit 19 may be several kilometres long.

For example, the treatment fluid injection conduit 19 comprises an upper pipe which runs from the wellhead 2 to the safety valve 17, a duct which is arranged in the safety valve 17, and a lower pipe which extends from the safety valve 17 to the production zone 10. The inner diameter of the pipes may be, for example, less than 1 cm, preferably less than 0.5 cm. The lower end of the treatment fluid injection conduit 19 comprises a

treatment fluid injection valve 22. Figures 2a, 2b, 2c illustrate an exemplary embodiment of the treatment fluid injection valve 22. The treatment fluid injection valve 22 comprises a tubular housing 30 which comprises a circumferential wall 36 and an upper end sub 31 which is secured at the upper axial end of the circumferential wall 36. A sleeve member 39 is fitted within the tubular housing 30 against a shoulder 42 of the circumferential wall 36 which extends radially inward. A seat member 32 is secured within the tubular housing 30 between the sleeve member 39 and the upper end sub 31.

A fluid inlet 37 is arranged in the upper axial end face of the tubular housing 30. The fluid inlet 37 is connected to the lower end of the treatment fluid injection conduit 19. A lateral fluid outlet 38 is arranged in the circumferential wall 36 of the tubular housing 30. The tubular housing 30 comprises an axial fluid passage 34 which extends through the upper end sub 31 and the seat member 32. The fluid inlet 37 is in fluid communication with the axial fluid passage 34. The sleeve member 39 comprises an axial fluid passage 40 which is in alignment with the axial fluid passage 34 so that the axial fluid passages 34, 40 of the tubular housing 30 and the sleeve member 39 are connected to each other.

The sleeve member 39 comprises at least one lateral fluid opening 41. In this exemplary embodiment, the sleeve member 39 comprises five rows of lateral fluid openings 41 (see figure 2c) . However, the sleeve member 39 may comprise any number of rows of lateral fluid openings. The lateral fluid openings 41 of each row are distributed circumferentially over the sleeve member 39, and the rows of lateral fluid openings 41 are arranged at an axial distance from each other. The lateral fluid openings 41 of the uppermost row have a smaller diameter than the lateral fluid openings 41 of lower rows. Thus, the flow area of the lateral fluid openings 41 in the row directly below the uppermost row is greater than the flow area of the lateral fluid openings 41 in the uppermost row .

The treatment fluid injection valve 22 comprises a piston member 43 which is radially surrounded by the sleeve member 39. The piston member 43 is moveably disposed within the axial fluid passage 40 of the sleeve member 39 between a closed position shown in figure 2a and a fully open position shown in figure 2c. The axial fluid passage 40 of the sleeve member 39 constitutes a piston chamber. The piston member 43 is disposed within the surrounding sleeve member 39 with a relatively close fit.

The piston member 43 is biased to the closed position by a spring member 50. In this exemplary embodiment, the spring member 50 comprises a compression spring which provides a bias force upon the piston member 43 for returning the piston member 43 toward the closed

position. The bias force can be adjusted by means of a setting screw 51 which is secured by a locking bolt 52.

The piston member 43 comprises an axial end surface 44 and an outer circumferential surface 45. The outer circumferential surface 45 of the piston member 43 is provided with a sealing member 46. As shown in figure 3, in this exemplary embodiment, the sealing member 46 comprises two metal piston rings 47 ("hard seal") and a resilient piston ring 48 ("soft seal") . Thus, the piston rings 46, 47 radially protrude from the outer

circumferential surface 45 and engage with the inner circumferential surface of the sleeve member 39 in a sealing manner. In the closed position as shown in figure 2a, the axial end surface 44 of the piston member 43 abuts against the seat member 32, in particular against a seat ring 33 which comprises a resilient material ("soft seal") . Thus, the piston member 43 in the closed position blocks treatment fluid flow from the axial fluid passage 34 toward the axial fluid passage 40 of the sleeve member 39. The sealing member 46 and the seat member 32 closes off the flow path from the fluid inlet 37 through the axial fluid passages 34, 40 and the lateral fluid openings 41 in the sleeve member 39 toward the lateral fluid outlet 38. The use of the sealing member 46 and the seat member 32 results in a very low leak rate, whereas the sealing member 46 also protects the seat member 32 against wear so that the treatment fluid injection valve

22 can be operated in a reliable manner for a long period .

The bias force exerted onto the piston member 43 by the spring member 50 can be overcome by the pressure of treatment fluid flowing into the axial fluid passage 34 in the tubular housing and acting onto the pressure- receiving axial end surface 44 of the piston member 43. When the pressure is increased within the treatment fluid injection conduit 19, it bears upon the pressure- receiving end surface 44 of the piston member 43 to urge the piston member 43 to move axially downward in the axial fluid passage 40 in the sleeve member 39. This unseats the piston member 43 from the seat member 32. By controlling the pressure of the treatment fluid, the piston member 43 can be moved in an incremental or continuously variable manner. Thus, the piston member 43 can be controlled to the partially open position shown in figure 2b ("throttling position") . In the partially open position shown in figure 2b, the piston member 43 has opened the lateral fluid openings 41 of the uppermost row. Thus, the piston member 43 permits treatment fluid flow from the fluid inlet 37 through the axial fluid passages 34, 40 and the lateral fluid openings 41 in the uppermost row of the sleeve member 39 toward the lateral fluid outlet 38 in the circumferential wall 36 of the tubular housing. As the piston member 43 still blocks the flow path through the lateral fluid openings 41 of the rows below the uppermost row, the flow area of the lateral fluid openings 41 of the uppermost row defines the volume flow of treatment fluid which flows out of the treatment fluid injection valve 22.

From the partially open position shown in figure 2b, the piston member 43 can be displaced over a further incremental distance so as to open the lateral fluid openings 41 of the row directly below the uppermost row of lateral fluid openings 41. Thus, the lateral fluid openings 41 in the sleeve member define an adjustable flow area which can be adjusted by controlling the position of the piston member 43 between the closed position shown in figure 2a and the fully open position shown in figure 2c.

As a result, the amount of treatment fluid to be discharged from the treatment fluid injection valve 22 can be accurately metered. In addition, when a chemical treatment fluid is used which leads to clogging of the lateral fluid openings 41 of the uppermost row, the piston member 43 can be temporarily displaced to a lower position so that the lateral fluid openings 41 of one or more lower rows are opened. Consequently, the volume flow of treatment fluid can be temporarily increased so as to wash away any caked residuals of treatment fluid and to clean the lateral fluid openings 41.

The piston member 43 can be displaced from the partially open position shown in figure 2b to the fully open position in figure 2c, wherein the lateral fluid openings 41 of each row are opened. With the piston member 43 in the fully open position, the lateral fluid openings 41 in the sleeve member 39 define a maximum flow area. As shown in figure 2c, the lateral fluid openings 41 of the lowermost row may still be partially covered by the piston member 43 in its open position.

The sleeve member 39, in particular the lateral fluid opening 41 or the lateral fluid openings 41 in the sleeve member 39, can be constructed in various ways. Figures 4a, 4b, 4d show exemplary embodiments of sleeve members having a single lateral fluid opening 41, whereas figure 4c illustrates the sleeve member 39 shown in figures 2a, 2b, 2c.

In a preferred embodiment, the injection valve of the invention has the following properties:

- the valve is able to seal at least in the range of about 250 bar to 350 bar of pressure at the inlet without leaking; and

- the valve can maintain a pressure at the inlet exceeding 350 bar while injecting less then 5 liter of treatment fluid per hour.

Please note that the above requirements imply relatively high pressures at low flow rates. Reference is also made to the conditions downhole, including

temperature, presence of corrosive materials. The targeted medium, i.e. the treatment fluid, may typically be a fluid having a density and viscosity which is substantially similar to water. However, the treatment fluid may in itself be corrosive, as the treatment fluid may typically comprise one or more acids or surfactans . In combination with the extended required lifetime of the injection valve in the order of multiple years, for instance at least 5 to 10 years, as well as the

significant costs and time involved to place or replace the injection valve in the wellbore, the hydrocarbon industry has an ardent desire for a reliable injection valve which can inject treatment fluid over prolonged periods of time.

Reference is made of Fig. 5. Basically, the injection valve 22 of the invention works like a two-stroke piston engine. Fluid is presented at the inlet 34, indicated by arrow 100, providing a fluid pressure Pfiuid to the top end 110 of the piston 43. The cylinder 43 is spring- energized and opens above a set pressure Έ^> _ορβη, to dose the fluid while maintaining the column pressure of the fluid. Depending on the fluid flow, the piston 43 will move down a certain distance, to find a balance while injecting .

Leakage of treatment fluid through an annular space

102 between the piston 43 and an inner surface of the cylinder 39 is relatively little. The tolerance between the wall of the piston and the wall of the cylinder 39 can be in the order of 0.5 to 3 μπι. The total diametrical difference may be about 5 μπι or smaller.

When closed (Fluid pressure Pfiuid < Popen) , the spring force 104 pushes the piston 43 against the static seal 33. In the static state, wherein the piston does not move and engages the seal 33, the injection valve can seal about 100%, i.e. is substantially leak-free. The static seal is for instance an o-ring, which is compressed into the correct shape and dimensions by the top end 110 of the piston 43, sealing on the top edge 106 of the piston. The assembly displayed in Fig. 5 may be placed in a protective housing 30 (See Figs. 2A to 2C) . The housing 30 may include a spring chamber comprising the

compression spring 50. An outer surface of the cylinder 39 may be provided with one or more annular seal rings

112 (Figs. 5, 6) to seal with respect to an inner surface of the wall 36 of the housing 30 .

In a practical embodiment, the cylinder 39 (Fig. 5) may have an internal bore 40, preferably a straight bore. The internal bore 40 may have a diameter in the order of about 5 to 30 mm, for instance about 10 mm. At a set distance below the static seal 33, one or more outlet ports 41 are located. The set distance may be in the order of the diameter of the internal bore.

Alternatively, the set distance may be at least 4 mm. The set distance may improve sealing abilities for the injecting state.

The outflow ports 41 may be shaped as shown in Figs. 2A to 2C. Alternatively, the outlet ports 41 may be shaped roughly triangular, or similar to a key hole, as shown in Fig. 6. The cross-sectional area of the outlet ports preferably increases in the direction wherein the piston 43 opens the ports. The shape of the outflow port increases the stability of the piston. Two or more outflow ports 41 may be provided to provide redundancy.

If one of the outlet ports 41 gets blocked, the injection valve 22 will still operate.

Referring to for instance Figs. 7 and 8, the static seal 33 may be placed in a cylinder head 114. The static seal preferably comprises an o-ring. The o-ring may be arranged in a corresponding groove 116 in the cylinder head 114, wherein the seal ring 33 is compressed by a seal compression ring 118 in order to obtain the right shape. The o-ring may be made from relatively hard, chemically resistant material, for instance a suitable polymer .

Fig. 8 shows a more detailed sectional view of the cylinder head assembly. When the fluid pressure drops below the set opening pressure of the valve, the spring force pushes the piston into the static seal 33, into the part thereof which bulges out of the groove between the cap ring 118 and the groove 116 of the cylinder head 114, creating a substantially 100% tight seal.

In a practical embodiment, the groove 116 may have a size of about 1,75 mm [w] * 2,1 mm [1] (Fig. 8) . Volume of the groove is about 107 mm³. The corresponding seal ring 33 may have an inner diameter ID of about 9,2 mm. The aforementioned exemplary sizes provide a static seal, wherein the piston 43 cannot push the o-ring 33 into the groove 116. As a result, even when the piston will deform the o-ring when engaging the static seal 33, the o-ring will provide a proper annular seal.

Referring to Figs. 9, 10 and 11, the top end of the piston is preferably provided with a labyrinth seal section 120. The labyrinth seal section may comprise a number of grooves 122. Between the grooves, corresponding raised flanges 124 are provided. The labyrinth may for instance comprise at least 10 circumferential grooves. The grooves may have a rectangular shape in cross-section

(Fig. 11) .

In a practical embodiment, the grooves may be about 0.5 to 1.5 mm deep, for instance about 1 mm deep. The grooves may be about 0.5 to 1.5 mm wide, for instance about 0,8 mm wide (Fig. 11) . The grooves 122, together with the piston wall 126 and the cylinder wall 40, create a labyrinth seal. The labyrinth seal increases the fluid friction with respect to just the annular space 102 between the piston 43 and the cylinder wall 40. The increased fluid friction decreases fluid leakage and thereby increases the distance travelled downwards by the piston away from the static seal, before fluid will flow through the valve and out of the outlet ports 41. The delayed fluid flow protects the static seal.

In an alternative embodiment, the grooves 122 may be arranged in the internal surface 40. In this embodiment, the outer surface of the cylinder 39 is preferably smooth .

In addition, the labyrinth seal may extend beyond the outlet ports 41, to also increase fluid friction in the annular space 102 in the section between the outlet ports and the spring chamber. Thus, the labyrinth seal also prevents the fluid from flowing down the stem of the piston 43 towards the spring chamber and the spring 50.

In a practical embodiment, the labyrinth grooves 122 extend over a length Ll of at least two times the distance L2 between the static seal 33 and the flow port 41. Alternatively, the length of the labyrinth seal L3 below the outlet port 41 is at least equal to, or greater than, the length of the labyrinth seal L2 between the outlet port 41 and the static seal 33 (Fig. 12) .

When the valve opens (the piston travels down from the static seal) , the sealing capability above the flow port decreases, causing the sealing capability below the flow port 41 to increase correspondingly. Since the fluids will follow the path of least resistance, which is out of the flow port 41 instead of down the stem of the piston 43, the fluid will not reach the spring chamber below the piston 43 (See for instance Fig. 13) .

The top end 110 of the piston may have a rounded edge 106, which protects the static seal. Radius of the edge may be about 0,4 mm (Fig. 11) . The piston 43 may have an outer diameter OD of about 9,995 mm. The cylinder 39 may have an innder diameter ID of 10 mm, creating a 5 μπι diametrical difference between the piston and the cylinder .

A labyrinth seal gets its sealing ability by breaking down the pressure in the fluid. This is done by creating turbulence in the fluid flow, which transfers the pressure into heat energy and thereby breaks down the pressure. A labyrinth seal consists of a number of grooves (a minimum may be about five grooves), creating the turbulence.

In the valve of the invention, the fluid first flows in a laminar flow through the inlet 34 into the annular space 102 (for instance about 2,5 μπι or less) .

Thereafter, the fluid enters the first groove 122a, where it heavily decelerates, causing turbulence. Within the groove, the fluid starts to rotate, stagnating laminar flow. From this turbulent flow, a section of fluid needs to shear off, in order to transfer through the subsequent section of the annulus 102, to the next groove 122b (Fig. 8) . In the next groove, the process starts over. The activator for this process is the pressure differential across the labyrinth seal.

In an embodiment, the hydraulic control line 18 for controlling the safety valve 17 and the injection conduit 19 for injecting treatment fluid in the wellbore may be combined in a single hydraulic conduit .

In use, a treatment fluid in the injection conduit 19 will be pressurized to a pressure exceeding a first threshold pressure Pi for opening the safety valve 17 but below a second threshold pressure P2 for opening the injection valve 22. The first threshold pressure is for instance in the order of 200 bar. The second threshold pressure may be in the range of about 2500 to 350 bar. The injection valve 22 according to the invention provides several advantages with respect to the prior art. Due to the separation of the static seal ring 33 and the dynamic seal, the static seal is not exposed to movement of the cylinder 43. The dynamic seal is

preferably provided by the labyrinth seal (Figs. 12 and 13) . This significantly improves the sealing ability of the static seal. In practice, the static seal of the injection valve of the invention can provide leak-free sealing.

Leak-free herein may be indicated by the following exemplary stress test results. The spring 50 was set at 32,5 mm for a bias pressure of about 250 bar (or 3625 psi) . The valve 22 was pressured up to 1500 psi (103 bar) to check for leakage, the pressure herein provided at the inlet 34. The pressure decreases about 54 psi (3.7 bar) in 2:13 min. This pressure decrease is probably caused by air in the system, settling of seals, etc. The pressure at inlet 34 was increased, until the valve opens at 4350 psi (300 bar) . Pressure was bled off, and set at 1500 psi

(103 bar) . After 10 minutes, pressure decreased about 20 psi (1.4 bar), indicating a good seal.

The leak rate in practice may be about 1 ml/hour or less for a distance between the inlet port 34 and the outlet port 41 of 4 mm or more, and using a piston having a smooth outer surface. The latter distance is comparable to the distance L2, shown in Fig. 12. The leak rate may be about 0.5 ml/hour or less for a distance between the inlet and the outlet of 10 mm and a smooth piston. The leak rate decreases for increasing distance L2. The leak rate also decreases when the piston is provided with the labyrinth seal section 120 (Fig. 9) . When using the labyrinth seal 120, the leak rate is for instance less then 0.3 ml/hour down to 0 ml/hour for a pressure differential of about 300 bar and a distance L2 of 4 mm or more .

In another exemplary test, the dynamic behavior of the injection valve 22 was observed. First, a relatively limited flow of fluid was applied to the inlet 34. The fluid flow was provides by an accumulator, providing a relatively stable fluid flow. The pressure at the inlet increased due to the continuous fluid flow, causing the valve to open when the pressure exceeded the second threshold pressure. Due to the limited flow, the pressure decreased again, causing the pressure to decrease and the valve to close again. The valve would open and close in a throttling manner. Thereafter, the fluid flow was lowered even further, causing the valve 22 to open and close less often, but still operating the same way, with perfect repeatability. This is visible in the graph of Fig. 15, in the left section thereof.

In another exemplary test, a single-stroke air- powered pump was used to supply a relatively large fluid flow to the inlet of the injection valve 22, causing the valve 22 to remain open while injecting. The strokes from the pump are also visible. A continuous stable injection (notwithstanding the pulsating supply from the pump) around 3500 psi was observed. A section close-up is shown in the graph of Fig. 14.

In yet another exemplary test, the opening pressure was set about 350 bar (or 5075 psi) , by setting the spring at about 45,5 mm. The valve opened at 5800 psi (400 bar) and closed when the pressure decreased to 4300 psi (297 bar) . This behavior was perfectly repeatable.

Again, with relatively low fluid flow rates, the valve throttled by opening and closing. At higher fluid injection rates, the valve opened continuously,

continuing injecting. This is shown in the graph of Fig. 15. In the left of Fig. 15, two sections 302, 304 of stable injection are visible, which are enlarged in graph 6 below. Later, the fluid flow was decreased, causing the injection valve 22 to open and close repeatedly (shown in section 306 of Fig. 15) . Fluid flow through the valve 22 can be increased or decreased, causing a corresponding increase or decreasing of the throttling frequency of the cylinder 43. The throttling behavior was maintained for 36 minutes .

The embodiment comprising the labyrinth piston configuration proved to be very reliable, providing repeatable behaviour over extended time periods. Relative to the behavior of other embodiments of the piston 43 (See for instance Fig. 2), the labyrinth piston

stabilizes at a lower pressure and/or fluid flow rate, which indicates better sealing capability. This was confirmed by other tests. Other types of the piston may leak a substantial amount of the (treatment) fluid into the spring chamber, i.e. the chamber holding the spring 50. In the series of tests referenced above,

substantially no leakage occurred when using the piston 43 provided with a labyrinth seal. The absence of leakage enables to prevent contact between the treatment fluid and certain parts of the valve, such as the spring 50. As the treatment fluid is typically highly corrosive, preventing contact with the spring reduces wear of the spring and significantly increases the lifetime of the valve. Due to the improved sealing of the labyrinth sealing section of the piston 43, the static seal 33 was not exposed to fluid flow and was able to properly close the valve in its static, closed position (compare to Fig. 2A) . In case of leakage, the lifetime of the static seal will be reduced. The latter is thus prevented in

combination with the labyrinth seal. In addition, the labyrinth seal makes the total design cheaper, easier to produce and more fail-safe. The above advantages were confirmed both in theory and during testing.

In a practical embodiment, the spring 50 may be set to 250 bar opening pressure. The valve may actually open at a pressure at the inlet 34 in the range of about 250 to 300 bar. The valve may close at a pressure at the inlet 34 in the range of about 205 to 230 bar.

Calculations indicated an expected opening pressure of about 252 bar, and an expected closing pressure of about

208 bar.

If the spring is set to about 350 bar opening pressure, the valve may actually open if the pressure at the inlet 34 is in the range of 360 to 400 bar. The valve may close if the pressure at the inlet 34 drops to about

270 to 300 bar. Calculations indicated an expected opening pressure of about 352 bar, and an expected closing pressure of about 285 bar.

Deviations of the opening pressure may be caused by the static seal. If the static seal ring 33 is compressed more than expected, the surface over which the fluid pressure at the inlet 34 should overcome the spring force is smaller. This corresponds with the observed behavior of the valve in practice.

A lot of prior art valves fail due to erosion of the seat which receives the moving parts of the valve.

Erosion occurs even when the seat is made from a very hard material, such as Tungsten Carbide. The erosion rate depends partly on the behaviour of the valve. Erosion is also caused by the way the foam is applied. Because gas production (and also liquid-loading) is usually

continuous, the foam is also applied continuously. Around 15 liter of treatment fluid per day may for instance be required for good deliquification . The treatment fluid may be applied 24 hours a day, 7 days a week. Thus, the valve may have to provide, and cope with, a continuous flow of 0.01 liter/min, which may increase up to 5 liter/min. Given the considerable pressure differential, which may be up to 200 to 300 bar or more, the valve only opens only a small gap between the ball and seat, causing high fluid speeds which may grind away the metal of the valve. In addition to that, a phenomenon called

cavitation occurs, a known problem cause in valves.

Cavitation is the formation of vapour cavities in a liquid, i.e. small liquid-free zones ("bubbles" or

"voids"), that are the consequence of forces acting upon the liquid. Cavitation usually occurs when a liquid is subjected to rapid changes of pressure that cause the formation of cavities where the pressure is relatively low. When subjected to higher pressure, the voids implode and can generate an intense Shockwave. Cavitation is a significant cause of wear. Collapsing voids that implode near to a metal surface cause cyclic stress through repeated implosion. This results in surface fatigue of the metal of the valve.

In the valve of the present invention, the rate of erosion is significantly reduced. The distance between the static seal 33 and the dynamic seal 120 prevents high flow rates of treatment fluid passing the static seal, and thus prevents the erosion of the seat, i.e. the static seal, as described above. When the valve of the invention opens, there will be a small fluid flow rate, so the static seal is protected. As the piston moves towards the outflow port, the fluid flow rate increases and the valve will stabilize. The piston top might wear a little due to the fluid flow, but this wear does not affect the static sealing capabilities, because the soft seal 33 is able to adapt to the wear of the piston top 106. Another plus side of the present design is that the piston is able to move and even vibrate when throttling, without making hammering contact with the static seal.

In prior art valve, this hammering metal-to-metal contact between the moving parts and the static seal often causes extensive wear of the valve seat.

The treatment fluid flow between the piston 43 and cylinder 39 can reach speeds up to 250 m/s, typically in the annulus 102 between the piston and the cylinder when the piston has at least partially moved to the open position. Such high speeds may cause erosion of

relatively soft materials. Since most corrosion-resistant materials are relatively soft, a wall of the internal bore 40 of the cylinder 39 and/or the outer surface of the piston 43 may be hardened. The wall of the bore 40 and/or the wall of the piston 43 may be hardened using one of the following methods .

1) Kolsterising® . This process uses diffusion of carbon into the surface. The Kolsterising® process does not coat the surface, but penetrates it, usually 20-30μηι deep [21] . This is required, since a coating could be sensitive to the wearing effect from the piston rings. For example, AISI316 stainless steel has a hardness of about 155 HV0.05, and after Kolsterising® the hardness may increase to about 900 to 1300 HV0.05. Kolsterising® is a good choice as it does not make the material more brittle, it does not change the shape or size of the material and decreases or even eliminates the chance of galling. More information about Kolsterising®, or a similar process Nivox®, can be obtained at Bodycote pic,

Springwood Close, Macclesfield (UK), SK10 2XF.

2) METCO®-16C. This is a Nickel-based coating, applied through flame spraying, which can raise the hardness of for example AISI316 stainless steel from 155 HV up to 700 HV0.05. The METCO®-16C coating is first applied, and subsequently the material is grinded down to the right dimensions, ending up with a hardened layer having a thickness in the order of, for instance, 5 to 10 μπι. METCO®-16C is provided by Sulzer Metco Management AG,

Switzerland.

A part of the valve of the invention that may be subjected to fluid erosion is the top 106 of the piston 43, as this top is located where the fluid is forced into the annulus 102 between the piston and the cylinder upon opening of the valve.

In an embodiment, both the wall of the internal bore 40 of the cylinder and the top section of the piston may be protected by a hardened layer. The top section of the piston herein includes the top end 110, edge 106, and at least a part of the wall of the piston 39. Said at least part of the wall of the piston includes for instance the raised flanges 124.

In a practical embodiment, a different hardening method is chosen for the internal bore 40 and the piston

39. In order to prevent galling, the piston is provided with METCO®-16C. The internal bore is processed using Kolsterising® .

There is a risk of galvanic corrosion related to applying a coating, such as METCO®-16C, instead of a surface treatment such as Kolsterising® in a corrosive environment like this. As mentioned before, to minimize the risk of erosion of the top of the piston, the surface thereof may be hardened by applying a coating, such as METCO®-16C. The coating has a different material

composition then the base material and is applied on the surface of the base material, where it infuses into the base material. This means the electrical conductivity between the two materials is near perfect, providing a potential for galvanic corrosion. To limit galvanic corrosion to acceptable levels for the puspose of fluid injection, the corrosion potential between the base metals of the piston and the metals of the coating is minimized. The corrosion potential is preferably less than a few hundred millivolts.

The standard potential of Inconel® 718, a good choice for the base material of the pison, is about -150mV. The standard potential of METCO®-16C is about -350mV. Herein, the potential difference is about 200mV. The coating is less noble and will work like an anode. Galvanic

corrosion might occur, but the corrosion rate will remain within acceptable limites.

The injection valve of the invention is able to function reliably during at least 2 years, and in practice much longer. The valve of the invention is therefore an enabling piece of equipment for the

injection of treatment fluid to limit liquid loading and to extend the lifetime of a wellbore.

The description above describes exemplary embodiments of the present invention for the purpose of illustration and explanation. It will be apparent, however, to the skilled person that many modifications to the exemplary embodiments set forth above are possible without

departing from the scope of the invention. It is noted that the features described above may be combined, each individually or in any combination of features, with one or more of the features of the claims.

Claims

C L A I M S

1. An injection valve for injecting treatment fluid in a wellbore, comprising:

- a cylinder (39) comprising a fluid inlet (34), at least one lateral fluid outlet (41), and an internal bore (40) providing a fluid passage from the fluid inlet towards the fluid outlet;

- a piston member (43) being moveably arranged within the internal bore (40) between a closed position and an open position, wherein in the closed position the piston member (43) blocks fluid flow from the fluid inlet towards the fluid outlet, and wherein in the open position the piston member (43) allows fluid flow from the fluid inlet (34) to the fluid outlet (41); and

- a labyrinth seal section (120) for sealing an annular space (102) between the piston member and an inner surface (40) of the cylinder at least between the fluid inlet (34) and the fluid outlet (41), the labyrinth seal section comprising a number of circumferential grooves (122) .

2. The valve of claim 1, wherein the circumferential grooves of the labyrinth seal section are arranged on the outer surface of the piston.

3. The valve of claim 1 or 2, wherein the labyrinth seal section (120) extends at least over a length (L2) between the fluid inlet (34) and the fluid outlet (41) .

4. The valve of claim 1, 2 or 3, wherein the labyrinth seal section (120) extends over at least twice the length (L2) between the fluid inlet (34) and the fluid outlet (41) .

5. The valve of any of claims 1-4, wherein a length (L3) of the labyrinth seal section (120) beyond the fluid outlet (41) is at least equal to, or greater than, the length (L2) of the labyrinth seal section between the fluid outlet (41) and a static seal (33) .

6. The valve of any of the previous claims, wherein the labyrinth seal section comprises at least 10 grooves.

7. The valve of any of the previous claims, wherein the labyrinth seal section extends beyond the fluid outlet.

8. The valve of any of the previous claims, wherein te grooves are square in cross-section.

9. The valve of any of the previous claims, the cylinder being enclosed by a protective housing (30), the housing being provided with a spring member (50) for biasing the piston at a threshold pressure P_open-

10. The valve of claim 9, the cylinder (39) being replaceably arranged in the protective housing (30) .

11. The valve of any of the previous claims, wherein a wall of the internal bore of the cylinder and/or a wall of the piston is provided with a hardened layer.

12. Wellbore, comprising:

- a sub-surface safety valve;

- a hydraulic control line for controlling the sub^¬ surface safety valve; and

- at least one injection valve according to claim 1.

13. The wellbore of claim 12, wherein the injection valve is arranged in the hydraulic control line, in a section thereof which extends downhole of the sub-surface safety valve, the hydraulic control line being adapted for controlling both the sub-surface safety valve and the at least one injection valve.

14. A method for injecting a treatment fluid in a wellbore (1), using an injection valve according to claim

1.

15. A method for injecting treatment fluid in a wellbore (1), comprising the steps of: - providing a sub-surface safety valve in the wellbore ;

- controlling a fluid pressure in the hydraulic control line to control the sub-surface safety valve and the at least one injection valve.

16. The method of claim 15, wherein the step of

controlling the fluid pressure comprises:

i) controlling the fluid pressure in a first pressure range between zero and a first threshold pressure (Pi), wherein the sub-surface safety valve and the at least one injection valve are closed;

ii) controlling the fluid pressure in a second pressure range between the first threshold pressure (Pi) and a second threshold pressure (P2, P_open) , wherein the sub-surface safety valve is open and the at least one injection valve is closed; and

iii) controlling the fluid pressure in a third pressure range exceeding the second threshold pressure (P2, Popen) r wherein the sub-surface safety valve is open and the at least one injection valve is open.