NO346128B1

NO346128B1 - Flow control device and method for well operations

Info

Publication number: NO346128B1
Application number: NO20190582A
Authority: NO
Inventors: Kristian Brekke
Original assignee: Flowpro Control As
Priority date: 2019-05-08
Filing date: 2019-05-08
Publication date: 2022-03-07
Also published as: NO20190582A1; WO2020225432A1

Description

FLOW CONTROL DEVICE AND METHOD FOR WELL OPERATIONS

Technical field

The invention relates to system for 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 particularly relates to a flow control device that is easily adjustable and time-efficient to adopt different configurations immediately before inserted into the well. The invention is particularly suitable for long, horizontal wells.

Technical background and object 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 for instance be 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 a tubular line 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 ICD 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 a 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 and circulation of breaker fluids, acid stimulation, and scale squeeze operations without the need for inner string or coiled tubing. This will save rig time and reduces risk when performing the operation.

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.

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 cover 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 operation.

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 10 % 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 one embodiment of the invention could be 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.

A mechanical operation of mechanical valves is a possible way to adjust the flow control device before installation. This approach is simple and robust. The operation however requires an added rig-time and it may introduce human error. It is therefore an object of the invention to provide a flow control device where each flow control device could be adjusted in a safe and quick manner where the rig time and risk of errors are highly reduced.

This is performed in the invention by adjusting the flow by an actuator arrangement.

All of the valve adjustments take place at surface condition. It is therefore preferable to use batteries, electric components, and wireless communication to adjust the flow control device. It is then possible to achieve a fully automatic, simultaneous adjustment and readjustment of each flow control device until the installation of the tubular line in the well. In operation, wireless data transfer communicates instructions like set points and confirmations between the operator and the flow control device. In addition, there may be a manual override as a back-up operation.

The flow control device will thus not require any additional rig time of personnel to be adjusted to a suitable flow characteristic.

There are some further advantages with this wireless connection.

Adjustments can adapt the completion to unexpected zone length/segments or formation quality.

If new wellbore data requires a blanked off section, this can be obtained by closing the flow control device without the use of blank pipe.

The flow control devices are adjusted to fully open if no choking is required.

If a shorter liner must be installed due to limiting hole conditions, last minute changes can be made to the flow control settings.

If hole-conditions prevent installation of swell packers, flow control devices may not be beneficial. All the flow control devices in the tubular line can in this case be set fully open to improve tracer and Production Log Test (PLT) interpretation.

Flow control device sections will arrive at the rig with preset settings according to the planned well design. However, if changes are required, this could be performed on the pipe deck. In addition, last minute changes can also take place on the drill floor due to the simplicity of the operation.

Summary of the invention

A flow control device for adjustment of the amount of fluid flowing out of and into a tubular pipe in an oil and gas well, comprising

- a housing,

- a plurality of openings extending radially through the housing between a reservoir outside the tubular pipe and an interior of the housing when used in the tubular pipe. The invention being distinctive in that the said flow control device further comprises an electrically powered actuator arrangement and a check valve arranged in connection with each of the plurality of openings, at least one of the check valves being configured to allow fluid flowing in one direction through the flow control device and at least one of the check valves being configured to allow fluid flowing in the opposite direction of the flow control device,

said respective actuator arrangement comprising an actuator and a piston arrangement operationally connected to the actuator,

said actuator is adapted to communicate with a wireless operated control device to adjust the position of the piston arrangement prior to installation in the well, wirelessly, in order to set the amount of fluid flowing through the flow control device and also the direction of the fluid flowing through each opening.

Preferably, said actuator arrangement being actuated through a wireless communication, such as wi-fi or Bluetooth or radio waves.

Preferably, the electrically powered actuator arrangement is powered by batteries.

Preferably, the housing comprises a plurality of openings disposed around the periphery of the housing, each opening being in operational connection with separately arranged actuator arrangements

Preferably, the piston arrangement comprises a cylinder having at least one orifice, and a piston arranged within the cylinder, said at least one orifice being arranged so that when said piston is moved longitudinally in the cylinder the at least one orifice being opened or closed depending on the direction of movement.

Preferably, the at least one opening and actuator arrangement being fluidly connected to a check valve allowing fluid to flow in one direction.

Preferably, the actuator arrangements are independently operable of each other.

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 any of the claims 1-4, fluidly connected to a base pipe, said screen joint and flow control device enclosing a part of the base pipe at each tubular segment.

The invention further relates to a method for adjustment of a production operation and treatment operation of a well within an oil or gas reservoir using a tubular line according to claim 10, wherein the method comprising the step of

-measuring the reservoir quality throughout the well,

-determining the optimal flow characteristic in each tubular segment,

-adjusting each flow control device of the respective tubular segments to the flow characteristic required using the actuator arrangement prior to installation in the well.

The invention also concerns the use of a flow control device according to any one of the claims 1-4, as a flow regulating device for production fluid and/or well treatment fluid in an oil and gas well.

Preferably the use of the claimed control device, wherein the oil and gas well is a horizontal well.

There is also described that 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, each of the ports having separately arranged actuator arrangements for moving the ports between a closed and open position.

Brief description of the drawings

Figure 1 shows a principle drawing of a horizontal well with a tubular line having a flow control device according to the invention

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

Figure 3-4 shows a perspective view of the flow control device according to an embodiment of the invention.

Figure 5 shows a detailed view of the flow control device from figure 3-4.

Figure 6 shows a detailed view of a flow control device according to a second embodiment of the invention.

Figure 7a and 7b illustrating examples of check valves that can be used in the various embodiments of the flow control device according to the invention.

Figure 8 shows a schematic view of a lay out and flow diagram for an embodiment of the flow control device according to the invention.

Figure 9 shows a schematic comparison of the oil production from produces with respectively a screen, a prior art flow control device or a flow control device according to the invention.

Figure 10 illustrating the simulated improved annulus acid coverage by a flow control device according to the invention compared to a regular inflow control device.

Figure 11 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 whole production/injection line constituting various repetitive 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 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 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.

With the term “wireless communication” it is meant a transfer of instruction between two or more points that are not connected physically. Examples of wireless connections could be radio waves, Bluetooth, wi-fi.

The term “flow characteristic” is meant the amount of fluid flowing out from or into the tubular line at each flow control devices and also the direction of the fluid flow.

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 comprising: 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 from the inside of the tubular line 1 through the flow control device 3 and the screen joint 4 and further into the formations 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 2 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 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 (figure 4, 6) of the base pipe 2 and the screen 4. The length of each segments 5, ie of each the base pipe 2 with screen 4 and 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 4 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 21b, 21a in figure 2. These coupling parts 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 11. 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 comprising the first and second base pipe part 2a, 2b, the screen joint or section 4 and a flow control device 3, 50 according to the present invention, assembled together as described above. The flow control device 3, 50 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, 50 and the screen joint 4.

Preferable flow control devices will be further described below and could be a flexible flow control device comprising a plurality of possible flow path directions; both for injection and production as shown in figure 3-5 and 6-7 with reference number 3 and 50 below.

The flow control device could also be a simple flow control device having only one opening connected to an actuator arrangement and thus possibility for only one flow path direction; injection or production.

During injection of treatment fluids to the well 10, the treatment fluid passes from an interior 30 (fig 3-7b) of the base pipe 2, through the flow control device 3, 50 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 11.

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, 50 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, 50 according to the invention has at least one check valve 16a, 16b for inlet or outlet of fluid to or from the screen joint 4. The flow control device 3, 50 has further a plurality of ports 15a, 15b or at least one opening 57a, 57b. The ports 15a, 15b or at least one opening 57 allows the fluid flowing from the outside of the flow control device 3, 50 to the inside of the flow control device 3, 50.

These features are shown in more detail in figures 3-5 and 6-7 as two different arrangements of the invention.

Figure 3 and 4 shows a perspective view of a first embodiment of the flow control device 50 according to the invention. This is a flow control device 50 with a plurality of openings 57 disposed around the periphery of the flow control device 50. The flow control device 50 may be installed both in a production mode or an injection mode depending on the position in the well and the surrounding well formations. The flexible flow control device 50 shown in the figures comprises a housing 51 (fig.4) with a plurality of openings 57 as illustrated in figure 3. In figure 4, each of the openings are covered by an erosion protective chamber 60.

Each of the openings 57 in the housing is in an operational connection with an actuator arrangement 53 (Fig.4). The actuator arrangement 53 comprises an actuator 55, for instance a linear actuator as disclosed in the figures, and a piston arrangement 54. The actuator 55 is operationally connected to the piston arrangement 54. The piston arrangement 54 comprises a cylinder 58 and a piston 59. The piston 59 is arranged within the cylinder 58 and is adapted to be moved longitudinally within the cylinder 58. The cylinder 58 further comprising a number of orifices 52a, 52b, 52c allowing fluid to flow between the inside of the cylinder to the erosion protective chamber 60 in the space between the opening 57 and the cylinder 58. Other arrangement for the flow from the cylinder 58 to the interior 30 of the flow control device 50 are also possible. The piston 59 and orifices 52a, 52b, 52c are arranged so that the piston 59 covers or exposed the orifices 52a, 52b, 52c when moved within the cylinder 58. The piston 59 is therefore able to adjust the number of orifices 52a, 52b, 52c that are covered or exposed in the piston arrangement 54.

This will regulate the number of orifices 52, 52b, 52c that allows fluid to flow through the flow control device 50 since the orifices 52a, 52b, 52c that are open are fluidly connected to the opening 57.

The actuator 55 is further communicating with a control device, such as electronic/controls 61, and/or wireless communication to adjust the position of the piston arrangement 54 and thus how many of the orifices 52a, 52b, 52c that are exposed and allow fluid to flow through.

The orifices 52a, 52b, 52c may have different diameter to vary the flow rate out of or into the flow control device. In figure 4 it is indicated that the orifices 52a, 52b, 52c can be 2.5 mm, 5 mm and 10 mm. The orifices 52a, 52b, 52c could however have equal diameter. Other diameters that in the example can also be possible embodiments of the invention. The number of orifices in communication with one opening 57 could also be different than three.

The flow control device 50 further has a check valve 16b fluidly coupled to each of the openings 57 to allow fluid to flow from the reservoir and screen joint through the flow control device 50 to the interior 30 of the tubular line 1. The flow control device 50 may also have a check valve 16a that are oriented the opposite way allowing fluid flow from the interior 30 of the tubular line 1 through the flow control device 50 to the screen joint 4 and reservoir. The check valve 16a, 16b could be a check valve having a fixed flow direction. The check valve 16a, 16b can however be a reversable check valve that may be set as an inflow check valve or outflow check valve, depending on the requirement of the actual flow control device 50. The check valve can for instance a check valve as illustrated in figure 7a, 7b. The invention is however not limited to these alternatives.

This adjustment of the flow control device 50 will further adapt the flow control device 30 to the actual reservoir and well conditions and stimulation requirements. This is performed at the rig deck or floor prior to the installation. Each flow control is thus set to the optimal operation, either for flow production, injection production or both, depending on the well.

The simplest embodiment of the invention is a flow control device with only one opening 57 and one actuator arrangement 53 as indicated above. This flow control device further has only one valve in fluid connection with the opening 57.

This embodiment is not shown in the figures.

A further embodiment of the invention has a number of openings 57 with associated actuator arrangements 53 and check valves 16a, 16b with the possibility of flow paths through the flow control device 50.

These arrangements are preferable disposed around the periphery of the flow control device 50 as shown in the figures.

Figure 5 shows a schematic view of several openings 57 fluidly connected to the actuator arrangement 53 and check valve 16a, 16b.

In the figure 5, the three uppermost arrangement shows the check valve 16a intended for flow from the flow control device 50 to the screen joint 4, while the three lowermost arrangements show the check valve 16b intended for flow from the screen joint 4 to the flow control device 50. This is only for illustration, other arrangements are also possible, for instance two nearby arrangements have opposite flow directions. The figure further illustrates how the piston 59 can move within the cylinder 58 and close the orifices 52a, 52b. The fluid flows to/from the opening 57 through the orifice(s) 52a, 52b that are not closed by the piston 59 and further to from the check valve 16a, 16b.

The actuator 55 is further communicating with a control device and further to a display to be operated wirelessly by persons at the installation surface prior to the whole tubular line is inserted into the well.

Figure 6 shows a simplified cross section of the flow control device 3 according to a second 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 6 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 6 shows further a second inlet 16b arranged in the housing 19 for the flow of production flow from the reservoir or formation 11 to the base pipe 2.

In figure 6 there is shown a plurality of inlet and outlet ports 15a, 15b.

The production fluid flows from an inlet or check valve16b through an annular space 14b between the base pipe 2 and the flow control device 3, 50 and further the open ports 15b or exposed openings 52. The well treatment fluid flows on the other hand from through the open ports 15a or exposed openings to the annular space 14a and further out through the outlet or check valve 16a. 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 can 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 valve16a, 16b of the flow control device 3.

Other illustrated examples in the figures are six ports 15a, 15b shown in figure 2 and eight ports 15a, 15b shown in figure 8. 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 opening or 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.

A preferable alternative over the manually operated port as described above, is to arrange an actuator (not shown) in connection with each of the ports 15a, 15b to open or close these ports remotely. There can for instance be one actuator per ports 15a, 15b for independently operation of each port 15a, 15b. The actuators are further communicating with a control device and further to a display to be operated wirelessly by personnel at the installation surface in a similar way as the first embodiment.

Figure 7a-figure 7b shows two possible embodiments of the inlet and outlet check valves 16a, 16b of the inlet control device 3. Both embodiments show check valves allowing flow in one direction only.

In the embodiment of figure 7a, 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 6 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 7b, the inlet and outlet are combined in one unit but have separate flow path through the flow control 3, 50. 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 7a. The production fluid and treatment fluid are guided through different valves or openings into and out of the housing 19, 51 of the flow control device 3, 50. 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 7b.

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, 50 may, as mention above, have a plurality of independent flow paths, for production and for injection. Each flow path is equipped with a number of ports 15a, 15b or openings 57 in parallel that can be opened or closed prior to installation.

The schematic layout and flow diagram for the flow control device according to the invention is illustrated in figure 8.

The production path P flows from the formation 11 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 11. 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 I1, 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.

This illustrated flow path could also illustrate the flow path of the control device according to the embodiment in figure 3-5. The nozzle is then illustrating the orifices 52a, 52b and the production/injection arrow flows to an opening and further into the tubular line 1.

The flow control device 3, 50 according to the invention is thus adjustable and each flow control device 3,50 arranged in each tubular segment 5 may be varied independently and remotely by a wireless communication with the attached actuator.

The operation of the tubular line 1 with the flow control device 3, 50 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 orifices and port 15b or orifice diameters. The flow control device 3, 50 according to the figures will be adjustable on site with up to a number of adjustments. A plurality of number is also possible, for instance 2, 3 or 8 as illustrated in the embodiments. One of these adjustments will be reserved for fully open as disclosed above. Fully closed valve will be obtained by closing all the ports 15b, 52a, 52b. 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, 50 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, 50.

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 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, 50 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 15a or orifices 52a, 52b in connection with the injection path I that are to be closed/open to obtain the desired flow through the flow control device 3.

Figure 9 shows a simulation of the oil production potential from applying the well data to adjust the flow control device at the time of installation. The example is illustrating an example from North Sea well producing with a maximum liquid production rate of 2000 Sm3/d in a sandstone formation with variable reservoir quality. The well has considerable water influx in the high permeability zones. By applying a flow control device that is uniform in the entire tubular line, it is possible to gain 10% more recovery than if a regular sand screen completion is used in the well. A further 10 % recovery is achieved if the permeability along the well path is used to adjust the flow control devices that are arranged throughout the tubular line. This is achieved by using the permeability information of the well to choke more along high permeability zones. In total, the figure 9 shows that there is a 20% increase in the recovery than with a screen completion.

A control device with a fast adjustment of the flow control device 3, 50 will make it feasible to perform these adjustments immediately before installation of the lower completion.

Figures 10 and 11 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 10 and a scale squeeze in figure 11.

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, … or orifices 52a, 52b 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 10 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 11, 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 11 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 adjustment of the amount of fluid flowing out of and into a tubular pipe (1) in an oil and gas well (10), comprising - a housing (19, 51),

- a plurality of openings (18a, 18b, 57) extending radially through the housing between a reservoir outside the tubular pipe (1) and an interior of the housing (19, 51) when used in the tubular pipe (1), characterized in that said flow control device (3, 50) further comprises an electrically powered actuator arrangement (53) and a check valve (16a, 16b) arranged in connection with each of the plurality of openings (18a, 18b, 57),

at least one of the check valves (16a) being configured to allow fluid flowing in one direction through the flow control device (3, 50) and at least one of the check valves (16b) being configured to allow fluid flowing in the opposite direction of the flow control device,

said respective actuator arrangement (53) comprising an actuator (55) and a piston arrangement (54) operationally connected to the actuator (55),

said actuator (55) is adapted to communicate with a wireless operated control device (61) to adjust the position of the piston arrangement (54) prior to installation in the well, wirelessly, in order to set the amount of fluid flowing through the flow control device and also the direction of the fluid flowing through each opening (18a, 18b, 57).

2. The flow control device (3, 50) according to claim 1, wherein said actuator arrangement (53) being actuated through wi-fi, Bluetooth or radio waves.

3. The flow control device (3, 50) according to claim 1 or 2, wherein said electrically powered actuator arrangement is powered by batteries.

4. The flow control device according to any one of the claims 1-3, wherein the piston arrangement (54) comprises a cylinder (58) having at least one orifice (52a, 52b), and a piston (59) arranged within the cylinder (58), said at least one orifice (52a, 52b) being arranged so that when said piston (59) is moved longitudinally in the cylinder (58) the at least one orifice (52a, 52b) being opened or closed depending on the direction of movement.

5. A tubular pipe (1) for use in an oil and gas well (10) for production and maintenance operation of said well (10), said tubular pipe (1) comprising at least one tubular segment (5), each tubular segment (5) comprising a screen joint (4) and a flow control device (3, 50) according to any of the claims 1-4, wherein the flow control device being fluidly connected to 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).

6. A method for adjustment of a production operation and treatment operation of a well (10) within an oil or gas reservoir using a tubular pipe according to claim 5, wherein the method comprising the step of

-measuring the reservoir quality throughout the well (10),

-determining the optimal flow characteristic in each tubular segment (5),

-adjusting each flow control device (3, 50) of the respective tubular segments (5) to the flow characteristic required using the actuator arrangement (53) wirelessly prior to installation in the well.

7. Use of a flow control device according to any one of the claims 1-4, as a flow regulating device for production fluid and/or well treatment fluid in an oil and gas well.

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