US20120061093A1

US20120061093A1 - Multiple in-flow control devices and methods for using same

Info

Publication number: US20120061093A1
Application number: US12/878,714
Authority: US
Inventors: Luis A. Garcia; Gonzalo Garcia
Original assignee: Baker Hughes Inc
Current assignee: Baker Hughes Holdings LLC
Priority date: 2010-09-09
Filing date: 2010-09-09
Publication date: 2012-03-15

Abstract

An apparatus controls flow of a fluid between a wellbore tubular and a wellbore using a particulate control device configured to be disposed in the wellbore and at least two parallel and directionally opposing flow paths in fluid communication with the particulate control device.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

None.

BACKGROUND OF THE DISCLOSURE

1. Field of the Disclosure
The disclosure relates generally to systems and methods for selective control of fluid flow into a production string in a wellbore.
2. Description of the Related Art
Hydrocarbons such as oil and gas are recovered from a subterranean formation using a wellbore drilled into the formation. Such wells are typically completed by placing a casing along the wellbore length and perforating the casing adjacent each such production zone to extract the formation fluids (such as hydrocarbons) into the wellbore. These production zones are sometimes separated from each other by installing a packer between the production zones. Fluid from each production zone entering the wellbore is drawn into a tubing that runs to the surface. It is desirable to control drainage along the production zone or zones to reduce undesirable conditions such as an invasive gas cone, water cone, and/or harmful flow patterns.
The present disclosure addresses these and other needs of the prior art.

SUMMARY OF THE DISCLOSURE

In aspects, the present disclosure provides an apparatus for controlling a flow of a fluid between a wellbore tubular and a wellbore. The apparatus may include a particulate control device configured to be disposed in the wellbore; and at least two parallel and directionally opposing flow paths in fluid communication with the particulate control device.
In aspects, the present disclosure also provides a method for controlling a flow of a fluid between a wellbore tubular and a wellbore annulus. The method may include separating a fluid flowing from a formation surrounding the wellbore into at least two parallel streams flowing in opposing directions; and generating a pressure drop in the at least two streams.
In aspects, the present disclosure further provides a method for controlling a flow of a fluid between a wellbore tubular and a wellbore. The method may include separating a fluid flowing between the wellbore annulus and a bore of the wellbore tubular into at least two parallel streams flowing in opposing directions; and generating a pressure drop in the at least two streams.
It should be understood that examples of the more important features of the disclosure have been summarized rather broadly in order that detailed description thereof that follows may be better understood, and in order that the contributions to the art may be appreciated. There are, of course, additional features of the disclosure that will be described hereinafter and which will form the subject of the claims appended hereto.

BRIEF DESCRIPTION OF THE DRAWINGS

The advantages and further aspects of the disclosure will be readily appreciated by those of ordinary skill in the art as the same becomes better understood by reference to the following detailed description when considered in conjunction with the accompanying drawings in which like reference characters designate like or similar elements throughout the several figures of the drawing and wherein:

FIG. 1 is a schematic elevation view of an exemplary multi-zonal wellbore and production assembly which incorporates an inflow control system in accordance with one embodiment of the present disclosure;

FIG. 2 is a schematic elevation view of an exemplary open hole production assembly which incorporates an inflow control system in accordance with one embodiment of the present disclosure;

FIG. 3 is a sectional view of an exemplary production control device made in accordance with one embodiment of the present disclosure;

FIG. 4 is schematic illustration of an in-flow control in a conventional well; and

FIG. 5 is a schematic view of an in-flow control device made in accordance with one embodiment of the present disclosure deployed in a high fluid flow velocity situation.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The present disclosure relates to devices and methods for controlling production of a subsurface fluid. In several embodiments, the devices describe herein may be used with a hydrocarbon producing well. In other embodiments, the devices and related methods may be used in geothermal applications, ground water applications, etc. The present disclosure is susceptible to embodiments of different forms. There are shown in the drawings, and herein will be described in detail, specific embodiments of the present disclosure with the understanding that the present disclosure is to be considered an exemplification of the principles of the disclosure, and is not intended to limit the disclosure to that illustrated and described herein. Further, while embodiments may be described as having one or more features or a combination of two or more features, such a feature or a combination of features should not be construed as essential unless expressly stated as essential.
Referring initially to FIG. 1, there is shown an exemplary wellbore 10 that has been drilled through the earth 12 and into a pair of formations 14, 16 from which it is desired to produce hydrocarbons. The wellbore 10 is cased by metal casing, as is known in the art, and a number of perforations 18 penetrate and extend into the formations 14, 16 so that production fluids may flow from the formations 14, 16 into the wellbore 10. The wellbore 10 has a deviated or substantially horizontal leg 19. The wellbore 10 has a late-stage production assembly, generally indicated at 20, disposed therein by a tubing string 22 that extends downwardly from a wellhead 24 at the surface 26 of the wellbore 10. The production assembly 20 defines an internal axial flow bore 28 along its length. An annulus 30 is defined between the production assembly 20 and the wellbore casing. The production assembly 20 has a deviated, generally horizontal portion 32 that extends along the deviated leg 19 of the wellbore 10. Production nipples 34 are positioned at selected points along the production assembly 20. Optionally, each production nipple 34 is isolated within the wellbore 10 by a pair of packer devices 36. Although only a few production nipples 34 are shown in FIG. 1, there may, in fact, be a large number of such nipples arranged in serial fashion along the horizontal portion 32.
Each production nipple 34 features a production control device 38 that is used to govern one or more aspects of a flow of one or more fluids into the production assembly 20. As used herein, the term “fluid” or “fluids” includes liquids, gases, hydrocarbons, multi-phase fluids, mixtures of two of more fluids, water, brine, engineered fluids such as drilling mud, fluids injected from the surface such as water, and naturally occurring fluids such as oil and gas. In accordance with embodiments of the present disclosure, the production control device 38 may have a number of alternative constructions that ensure selective operation and controlled fluid flow therethrough.
FIG. 2 illustrates an exemplary open hole wellbore 11 wherein the production devices of the present disclosure may be used. Construction and operation of the open hole wellbore 11 is similar in most respects to the wellbore 10 (FIG. 1) described previously. However, the wellbore arrangement 11 has an uncased borehole that is directly open to the formations 14, 16. Production fluids, therefore, flow directly from the formations 14, 16, and into the annulus 30 that is defined between the production assembly 21 and the wall of the wellbore 11. There are no perforations, and the packers 36 may be used to separate the production nipples. However, there may be some situations where the packers 36 are omitted. The nature of the production control device is such that the fluid flow is directed from the formation 16 directly to the nearest production nipple 34.
Referring now to FIG. 3, there is shown one embodiment of a production or injection control device 100 for controlling the flow of fluids between a reservoir and a flow bore 102 of a tubular 104 along a production string (e.g., tubing string 22 of FIG. 1). The control devices 100 may be distributed along a section of a production well to provide fluid control at multiple locations. This can be useful, for example, to impose a desired drainage or production influx pattern. By appropriately configuring the production control devices 100, a well owner can increase the likelihood that an oil or gas bearing reservoir will drain efficiently. This drainage pattern may include equal drainage from all zones or individualized and different drainage rates for one or more production zones. During injection operations, wherein a fluid such as water or steam is directed into the reservoir, the devices 100 may be used to distribute the injected fluid in a desired manner. Exemplary production control devices are discussed herein below.
In one embodiment, the production control device 100 includes a particulate control device 110 for reducing the amount and size of particulates entrained in the fluids and in-flow control devices 120 a,b that control overall drainage rate from the formation. The particulate control device 110 can include known devices such as sand screens and associated gravel packs. In embodiments, the in-flow control devices 120 a,b utilizes flow channels and/or other geometries that control in-flow rate and/or the type of fluids entering the flow bore 102 of a tubular 104 via one or more flow bore openings 106. Illustrative embodiments are described below.
In one embodiment, the in-flow control devices 120 a and 120 b are positioned at opposing ends of the particulate control device 110. The in-flow control devices 120 a,b each include flow passages 122 a,b that may include channels, orifices bores, annular spaces and/or hybrid geometry, that are constructed to generate a desired pressure differential across the in-flow devices 120 a,b. By hybrid, it is meant that a give flow passage may incorporate two or more different geometries (e.g., shape, dimensions, etc.). The flow passages 122 a,b are configured to convey fluid between the particulate control device 110 and the flow bore 102 along parallel and directionally opposing flow paths. By parallel, it is meant that the flow paths have a common origin and end point. By directionally opposing, it is meant that the flow passage 122 a directs the fluid in an axial direction opposite to the axial direction of the fluid in the flow passage 122 b. It should be understood, however, that the flow passages 122 a,b may utilize helical channels, radial channels, circular channels, etc. That is, the flow direction of the flow passages 122 a,b may use directional components in addition to an axial component. Also, in embodiments, the pressure control may be configured such that the pressure drop along the particulate control device 110 is substantially lower than the pressure drop in the pressure drop along the in-flow control devices 120 a, 120 b. This pressure drop may be the drop associated with the fluid flowing through the wall of the filtration media (e.g., the screen) and/or the fluid flowing between the wall of the filtration media and the base pipe 108. By “substantially,” it is meant an order of magnitude lower pressure drop. It should be noted that the fluid flow along the particulate control device 110 also has portions wherein two or more fluids streams have parallel and directionally opposite flows. That is, the flow paths between the base pipe 108 and the wall of the particulate control device 110 may direct flow substantially parallel to the long axis of the tool and in opposing directions.
During one exemplary use, a fluid F (liquid, gas, steam or mixture) may initially flow radially into the particulate control device 110 and split into a first fluid stream F1 and a second fluid stream F2. The fluid stream F1 flows through the inflow control device 120 a, which causes a pre-determined pressure drop in the fluid stream F1. Thereafter, the fluid stream flows through openings 106 into the flow bore 102. Similarly, the fluid stream F2 flows through the inflow control device 120 b, which causes a pre-determined pressure drop in the fluid stream F2. Thereafter, the fluid stream flows through openings 106 into the flow bore. The pressure drops in the fluid streams F1 and F2 may be the same or different. It should be noted that no fluid enters the flow bore 102 radially through a section 108 of the base pipe that is radially inward of the particulate control device 110. That is, all the fluid enters the flow bore at a location either uphole or downhole of the particulate control device 110.
While the teachings of the present disclosure may be applied to a variety of situations, certain embodiments of the present disclosure may be useful in controlling inflow patterns in relatively high-velocity flow rate situations. Referring now to FIG. 4, there is shown a production control device 150 disposed in a wellbore. The in-flow control device 150 may include a particulate control device 152 and an in-flow control device 154. A permeable material 156 may partially or completely fill an annular space 157 surrounding the particulate control device 152. This permeable material 156 may be a naturally occurring material such as sand that, over time, invaded the wellbore 152. The permeable material 156 may also be an engineered material such as gravel that has been pumped in from the surface. The permeable material 156 may act as a modulating media that moderates or distributes fluid flow 158 across the axial length of the particulate control device 152. Thus, the velocity of the fluid 160 flowing into the juncture 162 between the particulate control device 152 and the in-flow control device 154 may be significantly greater than the fluid inflow velocity at a distal point 164 on the particulate control device.
Referring now to FIG. 5, there is shown the FIG. 3 embodiment wherein the in-flow control devices 120 a and 120 b are positioned at opposing ends of the particulate control device 110. The annular space 170 around the particulate control device 110 does not include a flow modulating media. Rather, the annular space 170 may be open (standalone completion), include a material that is functionally the equivalent of an open space or include a permeable material (gravel pack completion), at least in terms of providing resistance to fluid flow. For purposes of this disclosure, the functional equivalent of an open space may be a material having a permeability of no less than 50 Darcy or a material that does not offer flow resistance in the radial and lineal direction.
In one situation, the formation may produce a fluid at a relatively high velocity, e.g., a gas or steam 172. It will be appreciated that if only one in-flow control device was present, e.g., in-flow control device 120 a, then all of the gas 172 would flow through the juncture 174 between the particulate control device 110 and the in-flow control device 120 a. The relatively high velocity may cause undesirable corrosion and/or erosion in the vicinity of the junction 174. Because two in-flow control devices are present, the gas 172 is divided into two streams 176 and 178. In one arrangement, each stream 176, 178 has one-half of the volume of the gas 172. Thus, the flow velocity at the juncture 174 has been reduced by approximately one-half, which reduces the amount of possible material degradation in the vicinity of the juncture 174. Additional in-flow control device can be considered but the solution will be restricted by the joint length.
From the above, it should be appreciated that what has been described includes, in part, an apparatus for controlling a flow of a fluid between a wellbore tubular and a wellbore annulus. The apparatus may include a particulate control device configured to be disposed in the wellbore; and two (or more) parallel and directionally opposing flow paths in fluid communication with the particulate control device. The flow paths may be configured to generate a substantially greater pressure drop than the particulate control device. A first flow path of the flow paths may be in fluid communication with a first end of the particulate control device and a second flow path of the flow paths may be in fluid communication with a second end of the particulate control device. The first and second ends may at opposite ends of the particulate control device. The particulate control device may include a fluid impermeable base pipe portion that may be radially inward of the particulate control device. The flow paths may be configured to generate a minimum flow into the particulate control device at a substantially medial location along the particulate control device. The particulate control device may be configured to generate fluid streams flowing in axially opposing directions.
From the above, it should be appreciated that what has been described also includes, in part, a method for controlling a flow of a fluid between a wellbore tubular and a wellbore annulus. The method may include separating a fluid flowing from a formation surrounding the wellbore into two (or more) parallel streams flowing in opposing directions; and generating a pressure drop in the streams. The method may include filtering the fluid before separating the fluid into parallel streams. The method may also include generating a substantially greater pressure drop in the streams than during filtering. The fluid may be filtered at a selected location in the wellbore, and the pressure drops may be generated uphole and downhole of the selected location. The method may include receiving a gas from the formation, the gas being the fluid. Also, the gas may be received through an open annular space.
From the above, it should be appreciated that what has been described further includes, in part, a method for control a flow of a fluid between a wellbore tubular and a wellbore annulus. The method may include separating a fluid flowing between the wellbore annulus and a bore of the wellbore tubular into two (or more0 parallel streams flowing in opposing directions; and generating a pressure drop in the streams.
It should be understood that the teachings of the present disclosure may readily be applied to other situations such as geothermal wells, water producing wells, etc.
For the sake of clarity and brevity, descriptions of most threaded connections between tubular elements, elastomeric seals, such as o-rings, and other well-understood techniques are omitted in the above description. Further, terms such as “slot,” “passages,” and “channels” are used in their broadest meaning and are not limited to any particular type or configuration. The foregoing description is directed to particular embodiments of the present disclosure for the purpose of illustration and explanation. It will be apparent, however, to one skilled in the art that many modifications and changes to the embodiment set forth above are possible without departing from the scope of the disclosure.

Claims

What is claimed is:

1. An apparatus for controlling a flow of a fluid between a wellbore tubular and a wellbore annulus, comprising:

a particulate control device configured to be disposed in the wellbore; and

at least two parallel and directionally opposing flow paths in fluid communication with the particulate control device.

2. The apparatus according to claim 1 wherein the at least two flow paths are configured to generate a substantially greater pressure drop than the particulate control device.

3. The apparatus according to claim 1, wherein a first flow path of the at least two flow paths is in fluid communication with a first end of the particulate control device and a second flow path of the at least two flow paths is in fluid communication with a second end of the particulate control device, the first and second ends being at opposite ends of the particulate control device.

4. The apparatus according to claim 1, wherein the particulate control device includes a fluid impermeable base pipe portion radially inward of the particulate control device.

5. The apparatus according to claim 1, wherein the at least two flow paths are configured to generate a minimum flow into the particulate control device at a substantially medial location along the particulate control device.

6. The apparatus according to claim 1, wherein the particulate control device is configured to generate two fluid streams flowing in axially opposing directions.

7. A method for controlling a flow of a fluid between a wellbore tubular and a wellbore annulus, comprising:

separating a fluid flowing from a formation surrounding the wellbore into at least two parallel streams flowing in opposing directions; and

generating a pressure drop in the at least two streams.

8. The method according to claim 7, further comprising filtering the fluid before separating the fluid into at least two parallel streams.

9. The method according to claim 8 further comprising generating a substantially greater pressure drop in the at least two streams than during filtering.

10. The method according to claim 8, wherein the fluid is filtered at a selected location in the wellbore, and the pressure drops are generated uphole and downhole of the selected location.

11. The method according to claim 7, further comprising receiving a gas from the formation, the gas being the fluid.

12. The method according to claim 11, wherein the gas is received through an open annular space.

13. The method according to claim 7, wherein a particulate control device is configured to separate the fluid.

14. A method for controlling a flow of a fluid between a wellbore tubular and a wellbore annulus, comprising:

separating a fluid flowing between the wellbore annulus and a bore of the wellbore tubular into at least two parallel streams flowing in opposing directions; and

generating a pressure drop in the at least two streams.

15. The method according to claim 14, further comprising filtering the fluid before separating the fluid into at least two parallel streams.

16. The method according to claim 15 further comprising generating a substantially greater pressure drop in the at least two streams than during filtering.

17. The method according to claim 8, further comprising flowing the fluid from the bore of the wellbore tubular to the wellbore annulus.