WO2020099433A1

WO2020099433A1 - Flexible flow control device

Info

Publication number: WO2020099433A1
Application number: PCT/EP2019/081068
Authority: WO
Inventors: Kristian Brekke
Original assignee: Flowpro Control As
Priority date: 2018-11-13
Filing date: 2019-11-12
Publication date: 2020-05-22
Also published as: NO20181454A1; NO345065B1

Abstract

The invention relates to a flow control device for use in a tubular pipe in an oil and gas well, comprising a housing (19), an inlet (16b) being fluidly connected to a screen and being configured to allow fluid to flow only in the direction from the screen to an interior (30) of the tubular pipe. The flow control device further comprises an outlet (16a) being fluidly connected to the same screen and being configured to allow fluid to flow only in the direction from the interior (30) of the tubular pipe to the screen. The devices further comprises two sets of ports (15a, 15b) which can be opened and closed independently from each other on the rig floor prior to installation.

Description

FLEXIBLE FLOW CONTROL DEVICE

Technical field

The invention relates to a flow control device for use in a production pipe for producing oil and gas from, or for injecting fluids into a well in an oil or gas reservoir. The invention is particularly suitable for long, horizontal wells.

Background of the invention

The most commonly used flow control for long horizontal wells is the static inflow control device known as ICD from publication NO306127. The technology in this publication was invented to mitigate reduced oil production due to uneven drawdown. The uneven drawdown was caused by frictional pressure losses along horizontal wellbores. In very high productivity reservoirs, the uneven drawdown caused reduced production from early gas breakthrough. The ICDs made it feasible to quadruple horizontal wellbore lengths by draining long horizontal wells more efficiently. The application of ICDs quickly expanded to balance drainage profiles along wells in heterogeneous formations. A more optimal drawdown profile could be achieved along the wellbore when used in combination with annulus packers so that there is created fluidly isolated zones in the well where each of the zones can drawdown fluid from the geological formation into the production pipe independently of the other zones.

The benefits from using ICDs can be for instance accelerated production, improved recovery and reduced cost of water and gas processing. For injection wells, ICDs can help distribute the injected water more evenly between zones, and if injecting above fracturing pressure, ICDs can mitigate excessive growth of individual fractures. This is beneficial for recovery and reduces the risk of out of zone injection. ICDs also cause positive side effects by reducing screen erosion and plugging.

However, all commercially available ICDs have identical flow characteristics in both production and injection directions, since it is necessary to inject/produce through the same opening in the ICD. ICDs are normally optimized for its primary purpose, to maximize oil production. However, significantly more aggressive choking is needed along the heel of the wellbore when bull-heading acid or scale squeeze than what is the optimal during production. Thus, if production and injection flow characteristics are identical, bull heading acid and inhibitors, or circulating breaker fluids along the wellbore, will be sub optimal.

During a stimulation, the acid will initially contact the heel part of the wellbore. Injectivity will start improving in the heel location as the acid dissolves the mud cake or works on the formation. This causes a higher injectivity and higher potential for the remaining acid to enter the heel section. In addition, the heel ICDs experience the largest pressure differential and the longest exposure to acid. Thus, the acid will tend to fill the heel part of the annulus, while the toe part may receive very little, or no acid at all.

To facilitate bull heading through the tubular line 1 with an even coverage throughout the wellbore, a different distribution of choke characteristics is needed along the wellbore than during the production mode. Current methods to ensure proper treatment along the entire wellbore is to pump fluids through a coiled tubing, or an inner string. However, this is combined with added cost and risk.

Without use of costly and risky coiled tubing operations, this can currently only be made more efficient by combining regular (two way) ICDs with check valve ICDs that will only allow production. If we use 50%/50% regular ICDs and check valve ICDs for a part of the wellbore, only 50% ICD flow area is open for injection, causing more aggressive choking during injection. However, the correct amount of different types of ICDs for expected well length, zone lengths and formation quality will need to be on site, including additional equipment for flexibility. This is costly and challenges the need for space, stockpiling and logistics. Also, with this approach only a fraction of the screen can be utilized for production as some screen sections are dedicated for treatment.

The publication US5435393 discloses an I DC with functionality for on location adjustability, However, ICDs have generally been manufactured as simple as possible without this feature. For the solution according to the invention, where ICDs have a wider functionality, on site adjustability is more critical to the proper function.

There is thus a need for a flow control that is usable for all screens throughout the tubular line for both injection modes and production modes.

There is also need for a flow control device where the individual and

independent flow characteristics for production and injection modes can be selected easily on the rig floor before installation. This will allow the flow control device to do an optimal job for production as well as when circulating breaker fluids, stimulating with acid or bull heading scale inhibitors.

The aim of this invention is to arrive at a more user-friendly flow control device design that can be easily adapted to well geometry and reservoir properties encountered after drilling and logging the wellbore. The improved design will also have dedicated functionality for placement of breaker fluids, acid

stimulation, and scale squeeze operations without the need for inner string or coiled tubing.

Thus, there is a need for a“one size fits all” flow control device with a rapid, flexible adjustment of flow characteristics for both production modes and treatment modes. The adjustment should be sufficiently fast and easy for it to take place on the location where the production pipe, screen and flow control device are to be installed, prior to the installation.

The flow control device according to the invention is beneficial in that it reduces the cost in implementation of the flow control device in the field.

The flow control device according to the invention can efficiently also perform scale squeeze operation without the use of expensive coiled tubing operations. The flow control device is further beneficial in that it efficiently circulates breaker fluids without the use of an inner string. This will save rig time and reduces risk when performing the operation.

Circulating breaker fluid through a regular inflow control device requires additional pumping to ensure coverage throughout the wellbore, the flow control device according to the invention will however have an optimized pressure control through the entire horizontal wellbore so that the breaker fluids covers the whole wellbore.

An optimized implementation of the flow control device according to the invention may save breaker fluid as less breaker fluid is required to efficiently perform the scale squeezer operations.

A further advantage of the flow control device according to the invention is to provide last minute adjustment of flow control device before installation. This will facilitate flow optimization based on actual well data. An increase of 1 0 % or more in oil production from the use of downhole flow control have been common for several fields.

If additional oil can be gained from optimizing flow using actual well data, additional revenues could be achieved.

To facilitate optimal treatment as well as production with the same flow control device, the flow control device according to the invention is equipped with independent flow paths for both injection and production directions. In a long horizontal well, several flow control devices are normally placed between packers. Closing some, or all of the injection nozzles for some or all of the ICDs provides adjustment flexibility. The respective flow control devices will arrive with pre-adjusted flow characteristics according to the planned well design. However, this setting can be altered on the pipe deck or drill floor.

Summary of the invention

The invention relates a flow control device for use in a tubular pipe in an oil and gas well, comprising a housing, an inlet arranged in the housing, said inlet being fluidly connected to a screen joint when used in the tubular pipe, said inlet being configured to allow fluid to flow only in the direction from the screen joint to an interior of the tubular pipe. According to the invention the flow control device further comprises an outlet arranged in the housing, said outlet being fluidly connected to the same screen joint when used in the tubular pipe, said outlet being configured to allow fluid to flow only in the direction from the interior of the tubular pipe to the screen joint, said inlet and outlet being check valves and the flow control device comprises two set of ports, a first set of ports being fluidly connected between the outlet of the flow control device and the interior of the tubular line, a second set of ports being fluidly connected between the inlet of the flow control device and the interior of the tubular line. The invention further relates to a method for adjustment of a production operation and treatment operation of a well, defined within an oil or gas reservoir, said well having a tubular line extending through a plurality of zones, each zone defined by a tubular segment of the tubular line throughout the well, said each tubular segment comprising a screen joint and the flow control device according to the invention fluidly connected to each other on a base pipe, said base pipe surrounding an interior of the tubular line. The method comprising the steps of allowing production fluid to flow through the inlet of the flow control device in a production mode, allowing well treatment fluid to flow through the outlet of the same flow control device in a well treatment mode

The invention further relates to a tubular pipe for use in an oil and gas well for production and maintenance operation of said well, said tubular line comprising at least one tubular segment, each tubular segment comprising a screen joint and a flow control device according to the invention, fluidly connected on a base pipe, said screen joint and flow control device enclosing a part of the base pipe at each tubular segment.

The invention also relates to the of the control device according invention, as a flow regulating device for production fluid and well treatment fluid in an oil and gas well. Preferable aspects of the invention are defined in the dependent claims, to which reference are made.

Brief description of the drawings

Figure 1 shows an overview of a horizontal well with a flow control device according to the invention installed in a tubular line in a horizontal well.

Figure 2 shows a detailed view of a section of the tubular line comprising the flow control device according to the invention.

Figure 3 shows a detailed view of an embodiment of the flow control device according to the invention.

Figure 4a and 4b shows possible embodiments of the check valve used in the flow control device according to the invention.

Figure 5 shows a schematic view of a lay out and flow diagram for the flow control device according to the invention.

Figure 6 illustrating the simulated improved annulus acid coverage by a flow control device according to the invention compared to a regular inflow control device.

Figure 7 illustrating the simulated improved scale squeeze inhibition by a flow control device according to the invention compared to a regular inflow control device.

Detailed description of the invention

The flow control device according to the invention is described in use with a horizontal well because flow control device is most effective in these kinds of well. The flow control device is however also possible to use in a vertical well, and the use is therefore not restricted to horizontal wells.

With the term“production mode” it is meant the recovery of fluids from a subterranean formation, ie when the fluid, mostly oil, gas or water flows from the surrounding geological formations of the well into the production line and further out of the well.

With the term“well treatment mode” or“injection mode” it is meant a circulation or squeeze operation where chemical, acid or other treatment fluid flows in the injection direction through the production line to the formation to perform work on the formation in order to increase the production rate from the well.

The“production mode” is stopped when performing the“well treatment mode” and vice versa.

With the term“tubular line 1” it is meant the production/injection line constituting segments where each of the segments comprising a base pipe, a flow control device and a screen joint. Several segments are assembled together

throughout the well.

With the term“annulus” it is meant the space between the geological formation and the tubular line in the well.

With the term“annulus space” is meant the space between the housing of the inflow control device and the second base pipe with the openings for fluid.

With the term“production fluid” it is meant any fluid that is present in the reservoir or formation that is allowed to flow into the tubular line. The fluids are mostly oil, gas or water. The production fluid follows a“production path” from the reservoir/geological formation to the into the tubular line 1.

With the term“treatment fluid” is meant chemicals, acid or other scale treatment fluid used in a maintenance operation to increase the productivity of the well, for instance by removing mud cake etc. that may build up in the annulus between the screen and the formation. The treatment fluid follows an“injection path” from the tubular line to the formation or screen.

Figure 1 illustrates an overview of a well 10 that is drilled horizontally through a geological formation 11. A tubular line 1 is inserted into the drilled well 10 to extract production fluids from a surrounding formation. The tubular line 1 could also be used to inject treatment fluids, such as acid, chemicals etc. for treatment operations of the well. The treatment operations can for instance be dissolving mud cake or similar operations to increase the productivity of the well 10. The tubular line 1 comprises of a base pipe 2, a flow control device 3 and a screen joint 4. The flow control device 3 and the screen joint 4 is arranged in connection with each other on the outside of the base pipe 2 for allowing production fluid to flow through the screen joint 4 to the base pipe 2 and further out of the well 10.

The tubular line 1 comprises a plurality of screen joints 4 and flow control devices 3 connected to the base pipe 2. A part of the base pipe that is not enclosed by a screen joint 4 and a flow device 3 is hereinafter referred to a first base pipe part 2a for simplicity. This base pipe part 2a does however not form a separate part of the base pipe 2. It is also the part of the pipe that is exposed to the surrounding well formation. A further second base pipe part 2b (figure 3) is covered by the flow control device 3 and the screen joint 4. The first and second base pipe part 2a, 2b of the base pipe 2 are not physically divided but forms a continuous base pipe 2 in each of the tubular segments 5 of the tubular line 1. The base pipes 2 are screwed together in approximately 12 m lengths along the well 10. Each of these tubular segments 5 have a screen 4 and a flow control device 3 to bring the fluid between the interior 30 of the base pipe 2 and the screen 4. The length of each segments 5, ie of each of the base pipe 2 with the screen 4 and the control flow device 3 is only an illustrating example, other lengths are possible embodiments.

The parts 2a, 2b, 3, 4 forming the tubular segment 5. The tubular line 1 in the well 10 may comprise a plurality of such tubular segments 5 in a repetitive combination as shown in figure 1.

As an illustrative example, the figure 1 shows 5 tubular segments 5 forming the tubular line 1. However, for long horizontal wells 10, it is not uncommon that the tubular line 1 comprises between 100-200 tubular segments 5.

The figure 1 further discloses connections 21 to connect two base pipes 2 together. This is illustrated by a male/female coupling part in figure 2. The respective coupling parts 21 a, 21 b are arranged at each free end of the base pipe 2 in each tubular segment 5.

In addition, there are arranged annulus packers 6 in the well. The packers 6 forms seals in an annulus 12 between the base pipe 2 and the surrounding formations 1 1. The packers 6 preferably surrounding the first base pipe part 2a. The packers 6 may be arranged in a number of possible ways. For instance, can there be several tubular segments 5 between each packer 6. There can for instance be a packer 6 between every 10^th tubular segment or joints 5.

Figure 2 shows a single tubular segment 5 from figure 1 in more detail.

The tubular segment 5 comprises the first and second base pipe part 2a, 2b, the screen joint or section 4 and the flow control device 3 assembled together as described above. The flow control device 3 is arranged at the end of the screen joint 4. The first base pipe part 2a defines the distance between each assembled flow control devices 3 and screen joint 4.

During injection of treatment fluids to the well 10, the treatment fluid passes from an interior 30 (fig 3) of the base pipe 2, through the flow control device 3, to an annular space 13 between the screen joint 4 and the base pipe 2. The treatment fluid further flows through the screen joint 4, into the annulus 12 and finally into the formation 1 1.

During production, this flow path is reversed and the fluid from the formations, mostly oil, gas or water, flows from the formation into the annulus 12 and further through the screen joint 4, the annular space 13, through the flow control device 3 to the interior 30 or the base pipe 2.

The screen joint 4 is formed as a filter, for instance a sand filter. The filter prevents grain or other particles from the formation to flow through the screen joint 4 and into the system 6.

The flow control device 3 according to the invention has check valves 16a, 16b for inlet or outlet of fluid to or from the screen joint 4. The flow control device 3 has further a plurality of ports or closing devices 15a, 15b. The production fluid flows from the inlet or check valve 16b through an annular space 14b between the base pipe 2 and the flow control device 3 and further the open ports 15b. The well treatment fluid flows on the other hand from through the open ports 15a to the annular space 14a and further out through the outlet or check valve

16a. These features are shown in more detail in figures 3-5 and will be described further in relation to these features.

Figure 3 shows a simplified cross section of the flow control device 3 according to an embodiment of the invention. There is shown a housing 19 having a first inlet 16a for injection of treatment fluid from the base pipe 2. The figure 3 shows a check valve 16a for the flow. The check valve 16a can be any of the type shown in figure 4 referred to as 16a’ and 16a”.

The flow control device 3 in figure 3 shows further a second inlet 16b arranged in the housing 19 for the flow of production flow from the reservoir or formation 1 1 to the base pipe 2.

In figure 2 there is shown a plurality of inlet and outlet ports 15a, 15b.

For simplicity, both injection and production paths are disclosed respectively with only two ports 15a, 15b. As an example, for the injection path, one port 15a is in the open position and the other port 15a is closed. A flow path for the injection path is illustrated by the arrows I.

As an example, for the production path, both ports 15b, 15b are open. A streamline for the production is illustrated by the arrows P. Although both production and injection streamlines are illustrated.

It should be noted that only production or injection occur at one time even though both streamlines are shown in the figure. The invention is however not limited to the two ports 15a, 15b arranged at each flow path of the injection control device 3. There may be arranged more than two ports in connection with each inlet or outlet check valve 16a, 16b of the flow control device.

Other illustrated examples in the figures are six ports 15a, 15b shown in figure 2 and eight ports 15a, 15b shown in figure 5. Other number of ports 15a, 15b may however also be possible embodiments of the invention.

One single port 15a, 15b in the inlet control device 3 is further illustrated by a threaded plug 17a, 17b and an orifice 18a, 18b. The threaded plug 17a, 17b is able to move between an open position and a closed position. In the open position the threaded plug 17a, 17b is moved away from the orifice 18a, 18b. In the closed position, the threaded plug 17a, 17b is closing over the orifice 18a,

18b to prevent fluid flowing through the port 15a, 15b.

The threaded plug 17a, 17b is arranged to be opened and closed by screwing the plug 17a, 17b in and out through the housing 19 of the flow control device 3. The orifice 18a, 18b is in the figure shown as an opening in the base pipe 2.

The respective plug 17a, 17b has further an end stop to prevent detachment from the flow control device 3.

The orifice 18a, 18b is more specifically arranged in an opening in the second base pipe part 2b that is extending at the inside of the inlet control valve 3.

The port 15a, 15b may however have other designs than a threaded plug 17a,

17b and orifice 18a, 18b. Any devices able to provide a fast, practical and robust on/off functionality will be possible embodiments for the port assembly in the inlet control device 3. Figure 4a-figure 4b shows two possible embodiments of the inlet and outlet check valves 16a, 16b of the inlet control device 3. Both embodiments show check valves.

In the embodiment of figure 4a, the check valves 16a’, 16b’ are separated for injection and production. There is in this embodiment thus arranged two set of ports 15a, 15b, one to each flow path. This embodiment is equal to the embodiment illustrated in figure 3 and disclosed above. The check valve is here a ball arranged in the respective inlet and outlet channels, to allow flow in one direction and prevent flow in the other direction.

The embodiment of figure 4b, the inlet and outlet are combined in one unit but have separate flow path through the flow control 3. There are also separate sets of ports fluidly connected to each of the flow path. In a similar way as in the embodiment of figure 4a. The production fluid and treatment fluid are guided through different valves into and out of the housing 19 of the flow control device 3. The inlet and outlet are shown as a channel with vertical flaps in each outlet/inlet. The vertical flaps are adapted to move out of the vertical position in opposite directions as shown in figure 4b.

Other check valves than the shown examples or inlet/outlet arrangement may be used as long as they are implementing a robust device with low pressure differential.

Check valves are used frequently throughout many industries, and it may be possible to implement already existing technology.

It is however necessary that the flow in the respective outlet 16b, 16b’, 16b” and the inlet 16a, 16a’, 16a” only have one flow direction. This will prevent injection of treatment fluid passing through the production path of the flow control device 3, and likewise prevent drain out of production fluid passing through the well treatment path of the flow control device 3.

The flow control device 3 has as mention above, two independent flow paths, one for production and one for injection. Each flow path is equipped with a number of ports 15a, 15b in parallel that can be opened or closed prior to the installation.

The schematic layout and flow diagram for the flow control device according to the invention is illustrated in figure 5.

The production path P flows from the formation 1 1 or screen joint 4 through the check valve 16a, 16a’ 16a” and one or more ports 15b1 , 15b2, ..15bn in the flow control device 3.

By varying the opening and closing of the ports 15b1 , 15b2 etc., there may be different flow rates into the base pipe 2 at each tube segment 5. The partial flow paths possible in one segment are referred to P1 , P2, P3.., Pn.

In similar way, the injection path I flows from the tubular line 1 through the ports 15a and the check valve 16a to the screen joint 4 or formation 1 1. By varying the opening and closing of the ports 15a1 , 15a2 etc, there may be different flow rates into the screen joint 4 or formation 11 at each tube segment 5. The partial flow paths are referred to 11 , I2, I3... In.

To adapt the flow control device 3 to the actual reservoir and well conditions, the production path has a number of ports 15b1 , 15b2 etc for flow adjustment in addition to a large diameter port 15n for fully open position. The stimulation scenario is more predictable but will require a large variation of choking along the well. Thus, the injection path I also has a number of ports 15a1 , 15a2 etc and one port 15an for fully open. Both the production and injection flow paths P, I, respectively is equipped with the check valve 16a, 16b that allows flow only in the intended direction.

It is to be noted that the flow rate through the set of ports 15a1 , 15a2..., 15b1 ,

15b2.. may be varied by how many of the ports that are open or closed in a set of ports 15a1 , 15a2..., 15b1 , 15b2..

The flow control device 3 according to the invention is thus adjustable and each flow control device 3 arranged in each tubular segment 5 may be varied independently.

The operation of the tubular line 1 with the flow control device 3 in a production mode will be further described below:

After the wellbore 10 is drilled and logged, parameters used in design of the flow control device 3 can deviate from expected values. Total length and number of tubular segments 5 between packers 6 and formation quality may be different from what was used to design the number of ports or nozzles and port 15b or nozzle diameters. The flow control device 3 according to the figure will be adjustable on site with up to 8 discrete levels of adjustment. This is however not limiting as other number of levels are possible. One of these adjustments will be reserved for fully open as disclosed above. Fully closed valve will be obtained by closing all the ports or nozzles 15b. The adjustment will take sufficiently small time to perform on site. It will not require any parts to be removed. The flow control device 3 does not need to be disassembled. This feature can provide the following added flexibility:

If new wellbore data requires that a section is shut off, this can be obtained by closing the flow control device 3.

If no choking is required for a zone, this can be obtained by adjusting the flow control device 3 to fully open.

Adjustments for unexpected zone length or formation quality can be handled by varying the adjustment within the 7 or other number of intermediate settings.

The fully closed position can also be used for the individual flow control devices in the respective tubular segments 5 to provide less flow control device 3 flow area and more aggressive choking for a specific zone. The fully open position can be used if no choking is required.

The respective flow control devices 3 for a specific well 10, will arrive at the rig with preset settings according to the planned well design. If changes are required, this will preferentially take place on the pipe deck prior to installation. However, last minute changes could also take place on the drill floor due to the simplicity of the operation.

The operation of the tubular line 1 with the flow control device 3 in an injection mode may in a similar way be adjusted by adjusting how many of the ports or nozzles 15a in connection with the injection path I that are to be closed/open to obtain the desired flow through the flow control device 3.

Figures 6 and 7 illustrates the effect of the flow control device 3 according to the invention compared to a regular flow device in a diagram. The simulations were performed with acid stimulation in figure 6 and a scale squeeze in figure 7. The fluids were simulated in a reservoir/well simulator with post processing in a dynamic wellbore model. The comparison is between stimulation through tubular line 1 with flow control devices chosen for optimal production (one 4 mm nozzle per joint) and a tubular line 1 where an increasing percentage of the flow control devices 3 flow area is closed for injection towards the heel of the wellbore (fewer nozzles activated for injection than production).

The table below defines the tubular line 1 divided into 16 zones. The table further defines how large percent of the ports 15a1 , 15a2,.. 15b1 , 15b2.. that are open for each zone in the simulation of treatment through control devices according to the present invention.

The wellbore has initially a skin of 100 to emulate damage and mud cake, except along the first 1000 m, where skin is reduced to 10 to emulate the acid initially working on the filter cake along the heel part.

Figure 6 illustrates the resulting annulus acid coverage for the two cases after 1 1/2 hours of pumping 1000 l/min. The acid coverage is given as number of annulus volumes placed at a certain location. For the prior art flow control device case, only a small portion of the acid reaches the second half of the wellbore, while the case with the flow control device according to the invention achieves a significantly better distribution of acid towards the toe of the well.

For the scale squeeze in figure 7, the well has a skin of 3 along the entire wellbore, and the treatment is bullheaded with a pump rate of 1000 l/min. The same flow control device and check valve configuration was used for this case. It is seen in figure 7 that the flow control device configurations according to the invention places significantly more of the treatment fluid towards the toe of the well. The present invention has been described with reference to a preferred embodiment and some drawings for the sake of understanding only and it should be clear to persons skilled in the art that the present invention includes all legitimate modifications within the ambit of what has been described hereinbefore and claimed in the appended claims.

Claims

1. A flow control device (3) for use in a tubular pipe (1 ) in an oil and gas well (10), comprising

- a housing (19),

- an inlet (16b, 16b’, 16b”) arranged in the housing (19), said inlet (16b,

16b’, 16b”) being fluidly connected to a screen joint (4) when used in the tubular pipe (1 ), said inlet (16b, 16b’, 16b”) being configured to allow fluid to flow only in the direction from the screen joint (4) to an interior of the tubular pipe (30),

said flow control device (3) comprises an outlet (16a, 16a’, 16a”) arranged in the housing (19), said outlet (16a, 16a’, 16a”) being fluidly connected to the same screen joint (4) when used in the tubular pipe (1 ), said outlet (16a, 16a’, 16a”) being configured to allow fluid to flow only in the direction from the interior of the tubular pipe (19) to the screen joint (4), said inlet and outlet being check valves (16a, 16a’, 16a”, 16a, 16b’,

16b”), characterised in that the flow control device comprises two set of ports (15a, 15b), a first set of ports (15a1 , 15a2..) being fluidly connected between the outlet (16a, 16a’, 16a”) of the flow control device (3) and the interior of the tubular line (30), a second set of ports (15b1 , 15b2..) being fluidly connected between the inlet (16b, 16b’, 16b”) of the flow control device (3) and the interior of the tubular line (30).

2. The flow control device according to claim 1 , wherein the ports (15a,

15b) are adapted to be opened and closed independently of each other.

3. The flow control device according to claim 2, wherein each port

comprising a threaded plug (17a, 17b) moveably arranged in the housing (19) and an orifice (18a, 18b) arranged in a base pipe (2) of the tubular pipe (1 ), said threaded plug (17a, 17b) is adapted to be moved to and from the orifice (18a. 18b) in order to prevent or allow the fluid flowing through the port (14a, 14b).

4. A method for adjustment of a production operation and treatment operation of a well (10), defined within an oil or gas reservoir, said well having a tubular line (1 ) extending through a plurality of zones, each zone defined by a tubular segment (5) of the tubular line (1 ) throughout the well (10), said each tubular segment (5) comprising a screen joint (4) and the flow control device (3) according to any one of the claims 1 -3 fluidly connected to each other on a base pipe (2), said base pipe (2) surrounding an interior of the tubular line (1 ), characterised in that the method comprising the steps of

-allowing production fluid to flow through the inlet (16b, 16b’, 16b”) of the flow control device (3) in a production mode,

-allowing well treatment fluid to flow through the outlet (16a, 16a’, 16a”) of the same flow control device (3) in a well treatment mode.

5. The method according to claim 4, wherein the method further comprises the steps of

-regulating the flow into the interior (30) of the tubular line by regulating a first set of ports (15a) in each inlet control device (3) adapted to be used in the production mode,

-regulating the flow out from the interior of the tubular line (30) by regulating a second set of ports (15b) in each control device (3) adapted to be used in the well treatment mode in order to adopt an optimized flow rate at each tubular segment during the production operation and the treatment operation.

6. The method according to claim 4 or 5, wherein the set of ports (15a, 15b) are respectively regulated to be open, partly open or closed in each tubular segment (5) of the tubular line (1 ).

7. A tubular pipe (1 ) for use in an oil and gas well for production and

maintenance operation of said well, said tubular line (1 ) comprising at least one tubular segment (5), each tubular segment comprising a screen joint (4) and a flow control device (3) according to any of the claims 1 -3, fluidly connected on a base pipe (2), said screen joint (4) and flow control device (3) enclosing a part of the base pipe (2) at each tubular segment (5).

8. Use of a control device according to any one of the claims 1 -3, as a flow regulating device for production fluid and well treatment fluid in an oil and gas well.

9. Use of a control device according claim 7, wherein the oil and gas well is a horizontal well.