Adjustable flow control devices for use in hydrocarbon production

Adjustable flow control devices for use in hydrocarbon production

Adjustable Flow Control Devices for Use in Hydrocarbon Production

Full description

Background of the invention

In general, detection is concerned with systems and methods for selective control of fluid flow between the wellbore tubular, such as the production string and subterranean formation.

Hydrocarbons such as oil and gas are recovered from subterranean formation using wellbore drilled in the formation. Typically, these wells are completed by placing casing along the wellbore length and casing perforation adjacent to this production zone in order to extract formation fluids (such as hydrocarbons) into the wellbore. Sometimes these production areas are separated from each other by installing a packer belt between the production areas. Fluid is drawn from each production zone entering the wellbore to the tubing that runs on the surface. It is required to have essentially equal drainage along the production zone. Uneven drainage may lead to unwanted conditions such as a diffuse gas cone or water cone. In the example of oil production, for example, a gas cone may cause an in-flow of gas into the wellbore, which may significantly reduce the oil-producing well. In a similar manner, a water cone may cause an in-flow of water into the oil production flow that reduces the quantity and quality of oil produced. Accordingly, it may be required to provide controlled drainage across the production area and/or the ability to optionally shut off or reduce in-flow within the production areas. Influx is not required for water and/or gas. Additionally, it may be required to inject fluid into the formation using a tubular wellbore.

The present disclosure addresses these and other needs of the previous method.

General description of the invention

In appearances, the present disclosure provides a device for controlling fluid flow between the wellbore tubular bore and the formation. The apparatus may include a body with at least two flow paths installed to deliver the fluid. The flow paths may be hydraulically isolated from each other in the body, and at least one of the flow paths may be occludable. In certain arrangements, each of two flow paths creates at least a different pressure drop in the fluid flowing through it. In certain representations, at least one of the flow paths includes a chamber and at least one opening in communication with the chamber. Other representations may include more than one chamber and one opening. For example, a flow path may include many chambers and each chamber must be in fluid communication with each other. In systems, each of the multiple flow paths includes many chambers, and each of the chambers may be in fluid communication with each other. Each of the flow paths may create a different pressure drop across them. In the given representations, the flow path has the first end in contact with the annulus of the wellbore and the second end in contact with the wellbore tubular bore. Also in regulations, the occlusion member 138 may block one or more flow paths.

In appearances, the present disclosure provides a method for controlling fluid flow between the bore of a wellbore tubular and the annulus of a well. The method may include creating at least two flow paths in the body and each of the two flow paths, with the first end in contact with the annulus and the second end in contact with the bore hole of the wellbore tubular, and creating at least one of two paths. At least two flow paths receive an occlusion member and hydraulically isolate at least two flow paths from each other in the body. The method may also include blocking at least one of at least two flow paths with an occlusion member. In the representations, the method may also include constructing at least two flow paths so as to create a different pressure drop in the fluid flowing through them. The method may also include installing at least one of at least two flow paths to include at least one chamber and at least one opening connected to the chamber. Also, the method may include installing at least one of at least two flow paths to include several chambers, with each of the chambers being in fluid communication with each other. Still also, the method may include the installation of at least two flow paths to include many chambers, and each of the chambers must be in fluid communication with each other, and where each two flow paths creates at least a pressure drop. Different pressure drop across it. The method may also include providing each of at least two flow paths with the first end in contact with the annulus of the wellbore and the second end in contact with the borehole of the wellbore tubular.

Still in other aspects, the present disclosure provides a fluid flow control system in the well. The system may include a wellbore tubular bore located in the well, a wellbore tubular bore with a flow bore, and a plurality of flow control devices placed along the length of the wellbore tubular. Each flow control device may include a body with several flow paths installed to conduct fluid between the annulus of the well and the flow bore. Each of the flow paths has the first end in contact with the annular shaft of the wellbore and the second end in contact with the flow bore, and each of the flow paths must be hydraulically isolated from each other between its own first ends and the second ends, where one is on Fewer than many flow paths can be optionally closed.

It should be understood that examples of very important features of the disclosure are particularly broadly summarized so that the detailed description that follows is better understood and that contributions to the method may be appreciated. There are, of course, additional features of the disclosure that will be described hereinafter and which will be the subject of the safeguards appended hereinafter.

Brief explanation of the drawings

The benefits and other aspects of the detection will be readily appreciated by those skilled in the art and will themselves become better understood by reference to the following detailed description when taken into account in conjunction with the accompanying drawings in which similar reference characteristics of the same or similar factors are designated through the various forms of drawings and where:

Figure 1 is a schematic high view of a typical multi-zonal wellbore and the production assembly that integrates the in-flow control system according to this representation to detect the current.

Figure 2 is a schematic high view of a typical open hole production assembly that integrates an in-flow control system with this representation of current detection.

Figure No. 3 is a schematic cross-sectional view of a typical production control device made according to this representation to detect current.

Figure 4 is a schematic view of the flow control system made according to this representation to detect the current

Figure 5 is a functional view of the unwrapped flow control device made according to this representation to detect the current.

Detailed description

The present disclosure concerns devices and methods for controlling fluid flow in a well. The present disclosure is effective in representations of various shapes. The specific representations of the current disclosure are presented there in drawings, and will be described here in detail, with the understanding that the current disclosure is taken into account as a representation of the principles of the disclosure, and it is not intended to limit the disclosure that is explained and described here.

Primarily referring to Figure 1, a typical wellbore 10 is shown that has been drilled through the ground 12 and into a pair of formations 14, 16 from which it is required to produce hydrocarbons. The wellbore 10 is caused by metal casing, as is known by the method, and the number of perforations 18 penetrates and extends into the formations 14, 16, where production fluids from the formations 14, 16 may flow into the wellbore 10. The wellbore 10 is essentially upright, leg 19, oblique or horizontal. The wellbore 10 wellbore has a late-stage production assembly, generally referred to at 20, which is placed here by a tubing string 22 that extends downward from the wellhead 24 at the surface 26 of the wellbore 10 wellbore. The production assembly is known as wellbore 10. assembly 20 internal axial flowbore 28 along its length. The annulus 30 annular shaft is known as between the production assembly 20 and the wellbore casing. The production assembly 20 has a skewed portion 32, generally horizontal that extends along the skewed leg 19 of the wellbore 10. The production assembly 34 is placed at selected points along the length of the production assembly 20. Optionally, each production device is isolated. 34 within a wellbore 10 with a pair of belt devices 36 packer devices. Although it shows only two production devices 34 in Figure 1, there may in fact be a large number of these production devices arranged in a serial fashion style along the horizontal section 32.

Each production device 34 includes a production control device 38 that is used to control one or more aspects of the flow of one or more fluids into the production assembly 20 production assembly. As used herein, the term fluid includes liquids, gases, hydrocarbons, multi-phase fluids, mixtures of two or more fluids, water, brine, engineered fluids such as drilling mud, fluids Injected fluids from the surface such as water, and naturally occurring fluids such as oil and gas. Additionally, references to water should be expanded to also include water-based fluids such as brine or salt water. According to representations of the present disclosure, the production control device 38 may have a number of alternative constructions that ensure optional operation and controlled fluid flow through it.

Figure 2 shows a typical open hole wellbore arrangement 11 where production devices of the present disclosure may be used. The wellbore construction and operation of the open hole wellbore 11 is similar in most respects to the wellbore wellbore 10 described previously. However, the wellbore arrangement 11 has an uncased borehole that opens directly into formations 14, 16. Therefore, production fluids flow directly from the formations 14, 16 and to the annular column annulus 30, which is located between the production assembly 21 and the wall of the wellbore 11. There are no perforations, and open hole packers 36 may be used to isolate production control devices 38. The nature of the production control device is such that it directs the fluid flow from formation 16 directly to the production control device 34 that is closest, thus leading to balanced flow. In some examples, packers may be omitted from open hole completion.

Referring to Figure 3, this representation of the production control device 100 is shown to control fluid flow from the reservoir to the production string or in-flow and/or flow control from the production column string. production string to reservoir, and out-flow. This flow control may be a function of one or more characteristics or parameters of the formation fluid, including water content, fluid velocity, gas content, etc. Furthermore, 100 control devices can be distributed along the production well section to provide fluid control at multiple specific locations. Typical production control devices are discussed here below.

In this representation, the production control device 100 includes a molecular control device 110 for reducing the amount and size of particles entering the fluid and a flow control device 120 that controls the overall discharge rate from the formation. The particulate control device 110 may include such well-known devices as sand screens and gravel packs.

In these representations, the flow control device 120 uses a plurality of flow paths or channels to create a predetermined pressure drop that helps control the flow rate and/or out-flow rate. One or more of these flow paths may be closed in order to provide an allocated pressure drop. A typical flow control device 120 creates a pressure drop to control flowing fluid channels through one or more conduit 122. Each conduit may be installed to provide an independent flow path between the flow bore 102 of the tubular 22 and the annular space or annulus 30 of the device separator device 120 of the configuration. Additionally, some or all of these conduits 122 may be essentially hydraulically isolated from each other. Therefore, flow through the 122 conduits may be considered parallel rather than in series. Thus, the flow through this conduit 122 may be partially or completely blocked without fundamentally affecting the flow through the other conduit. He should be understood as using the term parallel in a functional sense rather than suggesting a particular structure or physical configuration.

Referring now to Figure 4, there are shown other details of the flow control device 120, which creates a pressure drop by delivering the in-flowing fluid through one or more conduit 122 to a plurality of conduits 122. Each conduit may consist of conduit 122 along the wall of a base tubular or mandrel 130 and includes mounting features installed to control flow in a predetermined manner. While not required, the conduits 122 may be lined up in a parallel fashion and longitudinally along the mandrel axis 130. Each conduit 122 may have one end 132 in fluid communication with the tubular flow bore of the wellbore 102 (Figure No. 3) and the second end 134 which is in fluid communication with the annular space or the annular column 30 (Figure No. 3) flow control device separator 120 and formation. Generally, each conduit 122 is separated from one another, at least in a region between its respective ends 132 and 134. It is attached to the outer housing 136 shown by the mandrel 130 so that the conduits 122 are paths only for fluid flow. Cross spindle mandrel 130. In the representations, along the length of the mandrel 130, at least two conduits 122 provide independent flow paths between the annulus and the tubular flow bore 102 (Figure 3). One or more conduits 122 may be installed to receive an obstructive member that either partially or completely obstructs flow through that conduit 122. In this arrangement, the occlusion member may be a plug 138 that receives at the second end 134. For example, the plug 138 may be threaded or chemically attached to the first end 132. In other embodiments, the closure element may be attached to the second end 134. Still in other embodiments, the closure element may be located anywhere along the conduit 122.

In the representations, the conduits 122 may be arranged as a labyrinth that forms a tortuous or circuitous flow path for fluid flowing through the flow control device 120. In this representation, the conduits 122 may include series of chambers 142 which are associated with openings 144. During this exemplary use, fluid may initially flow into conduit 122 and be received into chamber 142. Then the fluid flows through the opening 144 and into the other chamber 142. The flow through the opening 144 may create a pressure drop greater than the flow through the chamber 142. The openings 144 may form as orifices, slots or other features that provide fluid communication between chambers 144. Fluid flow along a path The flow is labyrinth-like flow path until the fluid exits through either end 132 or end 134.

For ease of clarification, in a functional manner, Figure 5 displays the fluid flow paths for four conduits 122a, 122b, 122c and 122d as an illustration of the flow control device 120. For ease of clarification, the flow control device 120 is shown with phantom lines and is not wrapped. "unwrapped" in order to better visualize conduits 122A-D. Each of these conduits 122a, 122b, 122c and 122d provides a separate and independent flow path between the annulus 30 (Figure 3) or formation and the tubular flow bore 102. Also in the representation shown, each is provided with: Conduits 122A, 122B, 122C and 122D have a different pressure drop for flowing fluid. Conduit 122A is constructed to provide at least some resistance to fluid flow and thus provide a relatively small pressure drop. Constructing the conduit 122D in order to provide greater resistance to fluid flow and thus provide a relatively large pressure drop. The conduits 122b-c provide a pressure drop in a range between that provided by the conduits 122a-d. It should be understood, however, that in other representations, two or more conduits may supply the same pressure drop or that all conduits may supply the same pressure drop.

Referring now to Figures 4 and 5, as previously noted, the occlusion member 138 may be placed along one or more conduits 122a-d in order to prevent fluid flow. In some embodiments, the occlusion member 138 may be placed at the tip 132 as shown. For example, the occlusion member 138 may sharpen the plug or other similar factor. In other representations, the occlusion member 138 may also be placed at the tip 134. Still in other representations, the occlusion member 138 may be the material that fills the chambers or openings along the conduits 122a-d. The occlusion member 138 may be installed either partially or completely, preventing flow in the conduits 122a-d. Thus, fluid flow through the flow control device 120 may be controlled by selective blockage of one or more conduits 122. Of course the number of pressure drop fluctuations available varies with the number of conduits 122. Thus, in the representations, the flow control device 120 may provide the pressure drop associated with flow through this conduit or the composite pressure drop associated with the flow. Through two or more conduits.

Thus, in the representations, a flow control device may be constructed to be set or installed in the field to provide an optional pressure drop. For example, leaving conduits 122A-D unobstructed will increase the number of flow conduits and provide a lower pressure drop. To increase pressure drop, an occlusion member 138 may be installed in the conduit 122 to prevent fluid flow. Thus, in regulations, occlusion of conduits 122 using an occlusion member 138 may optionally be used to control the pressure differential created by the flow control device. Therefore, it must be estimated that a flow control device can be installed or re-installed in a good location to provide a pressure and back pressure differential in order to achieve the flow and drainage characteristics required for the reservoir and/or injection flow characteristics. Required injection flow characteristics.

Additionally, in the representations, some or all of the surfaces of the conduits 122 may be constructed to have a specified frictional resistance to flow. In some representations, friction may be increased by the use of textures, roughened surfaces, or other surface features. Alternatively, friction may be reduced by using polished or polished surfaces. In representations, surfaces may be covered with a material that increases or decreases surface friction. Furthermore, a coating may be installed to alter friction, depending mainly on the nature of the flowing material (such as water or oil). For example, the surface may be covered with a hydrophilic material that absorbs water to increase frictional resistance to water flow, and/or a hydrophobic material that resists water to reduce frictional resistance to water flow.

Referring generally to Figures 1 and 5, in one diffusion pattern, reservoirs 14 and 16 may be characterized by appropriate testing in order to estimate the desired drainage pattern or patterns. The required models may be obtained with the appropriate flow control devices 140 in order to create a specified pressure drop. The pressure drop may be similar or different for each of the flow control devices 140 placed along the tubular 22. Before inserting into the wellbore 10, formation assessment information such as formation pressure, temperature, fluid composition, wellbore geometry, and the like may be used to estimate the pressure drop required for each flow control device 140. The conduits 122 of each flow control device 140 may be blocked when necessary to achieve the desired pressure drop. Thus, for example, now referring to Figure 5, for the first flow control device, it may only block conduit 122a, for the second flow control device 140, it may only block conduits 122b and 122c, and for the flow control device. Device 140 III, may not block conduits 122A-D, etc. When installed to provide the required pressure drop, the wellbore 22 may be connected to a tubular wellbore along with inflow control devices 140 and installed in the well.

During this mode of operation, the fluid flows from the formation through the molecular control device 110 and then to the flow control device 140. The fluid also flows through the conduits 122, and a pressure drop occurs, which leads to a decrease in the flow velocity of the fluid. . In the other mode of operation, the fluid is pumped through the wellbore tubular 22 and through a flow control device 140. The fluid also flows through conduits 122 and a pressure drop occurs, which leads to a reduction in the flow velocity of the fluid flowing through the particulate control device 110 and to the annular column annulus 30 (Figure 3).

It should be understood that Figures 1 and 2 are intended to be illustrative only for production systems in which the instructions of the present disclosure may be used. For example, in certain production systems, wellbore wellbores 10, 11 may use only casing or lining to deliver production fluids to the surface. The instructions of the present disclosure may be used to control flow into these and wellbore tubulars.

It should also be appreciated that conduits may also include a permeable medium. Conduit permeability may be controlled by appropriate selection of permeable medium. Generally mentioned, the amount of surface area along the length of the conduit, the cross-sectional flow area of the conduit, the tortuosity of the conduit, among other factors, determines the permeability of the conduit. In this representation, the permeable medium may be formed using agents that encapsulate the conduit. The agents may be granular elements such as packed ball bearings, beads or pellets, and fiberous elements such as steel wool or any other factor that creates the interstitial spaces through which the fluid may flow. . Factors may also be a burden on capillary tubes arranged to allow flow through the conduit. In other representations, the permeable medium may include one or more bodies in which pores may form. For example, the body might be a sponge-like object or a stack of filter-type elements that perforate. It will be estimated that appropriate selection of the dimensions of objects such as beads, the number, shape and size of pores or perforations, the diameter and number of capillary tubes, etc. may produce the permeability required for the pressure drop chosen. Thus, these factors may be used instead of or in addition to the chambers described previously.

It should be appreciated that what has been described includes, in part, a control device for fluid flow between the wellbore tubular and the formation. The apparatus may include a body having two or more flow paths for fluid delivery. Flow paths may be hydraulically isolated from each other in the body, and at least one of the flow paths may be obstructed. In some systems, each flow path creates a different pressure drop in the fluid flowing through it. In certain representations, at least one of the flow paths includes a chamber and at least one opening connected to the chamber. Other representations may include more than one chamber and opening. For example, the flow path may include many chambers, and each of the chambers must be in fluid communication with each other. In systems, each of the multiple flow paths includes many chambers, and each of the chambers is in fluid communication with each other. Each flow paths may create a different pressure drop through it. In the given representations, each of the flow paths has the first end in contact with the annular shaft of the wellbore and the second end in contact with the wellbore tubular bore. Also in regulations, an occlusion member may block one or more flow paths.

It must be appreciated that what has been described includes, in part, a method for controlling fluid flow between the wellbore tubular bore and the annulus of the well. The method may provide for the formation of at least two flow paths in the body, each of the two flow paths having the first end in connection with the annulus and the second end in connection with the bore hole of the tubular wellbore, and consisting of at least one of At least two flow paths for the occlusion membe to receive and hydraulically isolate at least two flow paths from each other in the body. The method may also include blocking at least one of two flow paths with an occlusion member. In representations, the method may also include fitting each of the flow paths to create a different pressure drop in the fluid flowing through it. Also, the method may include installing at least one flow paths to include the chamber and at least one opening connected to the chamber. Also, the method may include the installation of at least one flow paths to include several chambers, and each of the chambers must be in fluid communication with each other. Still further, the composition may include at least two flow paths in order to include a plurality of chambers, provided that each of the chambers is in fluid communication with each other, and where each of the two flow paths arises on The least different pressure drop through it. Also, the method may include providing each of at least two flow paths with the first end in contact with the annulus of the wellbore and the second end in contact with the orifice of the wellbore tubular bore.

It should be estimated that what has been described includes, in part, the well's fluid flow control system. The system may include a wellbore tubular bore located in the well, a wellbore tubular bore with a flow bore, and several flow control devices. It may include a body with several flow paths installed to conduct the fluid between Annulus column for well and flow bore, Each of the flow paths has the first end in contact with the annular shaft of the wellbore and the second end is in contact with the flow bore, and each of the flow paths must be hydraulically isolated from each other between its own first ends and the second ends, where Many flow paths can be optionally closed.

For the sake of clarity and brevity, it omits descriptions of most threaded connections between tubular elements, elastomeric seals such as O-rings, and other techniques well understood in the previous description. Also, terms such as “valve” are used in a broad sense and are not limited to any special type or combination. The above-mentioned description is directed to special representations to reveal the current for the purpose of clarification and explanation. It will appear, however, to the skilled person that he means a lot.

Modifications and changes of previously established representations are possible without leaving the detection field.