WO2011106579A2

WO2011106579A2 - Wellbore valve, wellbore system, and method of producing reservoir fluids

Info

Publication number: WO2011106579A2
Application number: PCT/US2011/026146
Authority: WO
Inventors: Henning Hansen; Bernt Sigve Aadnoy; Cynthia B. Conroy
Original assignee: Hansen Energy Solutions Llc
Priority date: 2010-02-25
Filing date: 2011-02-25
Publication date: 2011-09-01
Also published as: WO2011106579A3

Abstract

A wellbore valve includes a valve body having an inlet port, an outlet port, and an axial bore. A screen is mounted on the valve body and positioned in a flow path between an exterior of the valve body and the inlet port for filtering a fluid flowing into the inlet port along the flow path. A valve member is disposed in the axial bore. The valve member is movable relative to the valve body between a first valve position where the valve member opens up the inlet port to the axial bore and closes off the outlet port from the axial bore and a second valve position where the valve member closes off the inlet port from the axial bore and opens up the outlet port to the axial bore.

Description

WELLBORE VALVE, WELLBORE SYSTEM, AND METHOD OF PRODUCING RESERVOIR FLUIDS

TECHNICAL FIELD

[0001] The invention relates generally to methods and apparatus for producing reservoir fluids from wells.

BACKGROUND

[0002] It is common to stimulate oil and gas wells in order to increase the rate at which reservoir fluids are produced from the wells. For example, gas shale and "tight" gas reservoirs have very low permeability and often require stimulation to achieve feasible gas production. Stimulation involves using stimulation fluid to create fractures in formation zones traversed by the well and to transport and evenly distribute propping material, e.g., proppants and/or sand, in the fractures. The propping material is intended to prop up the fractures so that the fractures do not collapse while reservoir fluids are being drawn from the formation zones.

Liquids, foams, and gaseous fluids are generally used to create highly conductive fracture systems in rock formations.

[0003] One common method for completing and stimulating a long-reach horizontal well involves installing a well completion including a number of so-called "fracturing sleeve," or more commonly "frac sleeve," valves and zonal isolation devices in the well. Frac sleeve valves are sliding-sleeve-type valves that are opened sequentially to stimulate formation zone by formation zone. These valves are typically opened by dropping balls, which are made of steel or other hard material, of various dimensions into the well. The ball lands in a seat on a sleeve within the valve. Thereafter, fluid pumping into the well is increased to open the valve. Once the valve is opened, the formation zone adjacent to the valve can be stimulated.

[0004] Once the frac sleeve valve is opened, it typically cannot be closed again. Through the open valve, stimulation fluid with a high content of propping material can be pumped into the adjacent formation zone to create fractures in the formation zone and fill the fractures with the propping material. However, the open valve will also allow the propping materials in the fractures to flow back into the well when the well is hydraulically connected to produce fluids. A large loss of propping material from the fractures may cause the fractures to collapse, resulting in decreased production or no production of fluids from the formation zone.

[0005] While producing a well, it may be necessary to shut off one or more individual formation zones traversed by the well. Complex intervention is typically required to shut off individual formation zones. One type of complex intervention requires installing a straddle packer (annular seal) system in the well, which would result in reduced internal diameter of the well for accessing below the straddle packer system. Another type of complex, and costly, intervention involves injecting sealant materials, such as epoxy, into formation zones to shut off, i.e., hydraulically seal, the zones. Yet another type of complex, and costly, intervention involves installing an intelligent completion system in the well, where a valve can be closed via one or several service lines from the Earth's surface.

[0006] Commingling production from several individual formation zones in a single well traversing the formation zones is prohibited in some geographic locations, typically due to government regulations or different ownership of various reservoir sections. For example, the Mineral and Management Service in the United States requires that fluids produced from several formation zones are not

commingled. This requirement is prompted by the need to know how much each formation zone produces. Thus, along with not commingling production comes the requirement to know the inflow and outflow rates of individual formation zones. Measuring such individual flow rates can be complex and costly. A probable solution may involve installing so-called intelligent completions with downhole flow measurements. SUMMARY

[0007] In one aspect, a wellbore valve includes a valve body having an inlet port, an outlet port, and an axial bore. The wellbore valve further includes a screen mounted on the valve body. The screen is positioned in a flow path between an exterior of the valve body and the inlet port for filtering fluid flowing into the inlet port along the flow path. The wellbore valve includes a valve member in the axial bore. The valve member is movable relative to the valve body between a first valve position where the valve member opens up the inlet port to the axial bore and closes off the outlet port from the axial bore and a second valve position where the valve member closes off the inlet port from the axial bore and opens up the outlet port to the axial bore.

[0008] In another aspect, a wellbore valve includes a valve body having an inlet port including a choke, an outlet port including a one-way valve, and an axial bore in communication with the inlet port and the outlet port. The wellbore valve further includes a screen mounted on the valve body. The screen is positioned in a flow path between an exterior of the valve body and the inlet port for filtering fluid flowing into the inlet port along the flow path.

[0009] In another aspect, a wellbore system includes at least one wellbore valve disposed in a well. The at least one wellbore valve has an inlet port, an outlet port, a valve member movable between a first valve position where the valve member opens up the inlet port and closes off the outlet port and a second valve position where the valve member closes off the inlet port and opens up the outlet port, and a screen in a flow path between an exterior of the at least one wellbore valve and the inlet port for filtering fluid flowing into the inlet port along the flow path. The wellbore system further includes at least one zonal control device disposed in the well for isolating a formation zone traversed by the well.

[0010] In another aspect, a method of producing fluids from a well includes (a) installing at least one wellbore valve as described above in the well and (b) moving the valve member to the first valve position to allow a fluid from a formation traversed by the well to flow into the inlet port through the flow path.

[0011] In another aspect, a wellbore system includes a first tubing disposed in a well traversing a first formation zone and a second formation zone, where the first tubing is hydraulically connected to the first formation zone. The wellbore system further includes a second tubing disposed in the well, where the second tubing is hydraulically connected to the second formation zone. The wellbore system further includes at least one zonal isolation device for isolating the first formation zone from the second formation zone. At least one wellbore valve as described above is disposed along at least one the first and second tubings.

[0012] It is to be understood that both the foregoing summary and the following detailed description are exemplary of the invention and are intended to provide an overview or framework for understanding the nature and character of the invention as it is claimed. The accompanying drawings are included to provide a further understanding of the invention and are incorporated in and constitute a part of this specification. The drawings illustrate various embodiments of the invention and together with the description serve to explain the principles and operation of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

[0013] The following is a description of the figures in the accompanying drawings. The figures are not necessarily to scale, and certain features and certain views of the figures may be shown exaggerated in scale or in schematic in the interest of clarity and conciseness.

[0014] FIG. 1 is a schematic of wellbore valves arranged along a well.

[0015] FIG. 2A is a cross-section of a wellbore valve.

[0016] FIG. 2B is a cross-section of a wellbore valve and a ball dropped into the wellbore valve for opening the wellbore valve for stimulation.

[0017] FIG. 2C is a cross-section of a wellbore valve and a ball dropped into the wellbore valve for opening the wellbore valve for stimulation. [0018] FIG. 2D is a cross- section of a wellbore valve and a dart dropped into the wellbore valve for opening the wellbore valve for stimulation.

[0019] FIG. 3A is a cross- section of a wellbore valve with open inlet ports and closed outlet ports.

[0020] FIG. 3B is a cross-section of a wellbore valve with closed inlet ports and open outlet ports.

[0021] FIG. 3C is a cross-section of a wellbore valve with closed inlet ports and closed outlet ports.

[0022] FIG. 3D is a partial cross-section of a wellbore valve.

[0023] FIG. 4A is a partial cross-section of a wellbore valve for use in a "huff-n- puff ' well.

[0024] FIG. 4B is a partial cross-section of a wellbore valve for use in a "huff-n- puff ' well.

[0025] FIG. 4C is a cross-section of a wellbore valve for use in a "huff-n-puff ' well.

[0026] FIG. 5 is a schematic of a well containing two tubings for production.

DETAILED DESCRIPTION

[0027] Additional features and advantages of the invention will be set forth in the detailed description that follows and, in part, will be readily apparent to those skilled in the art from that description or recognized by practicing the invention as described herein.

[0028] In FIG. 1, a well completion 101 including a tubing 100 is disposed in a well 102. The well completion 101 also includes one or more zonal isolation devices 104, each of which extends between the wall 106 of the well 102 and the tubing 100. The zonal isolation devices 104 may be carried into the well 102 on the tubing 100 and then activated to engage the wall 106 of the well 102. In one embodiment, the zonal isolation devices 104 are swellable, inflatable, or mechanically-activated packers. The zonal isolation devices 104 are used to segment the well 102 into well sections 110. The well completion 101 also includes one or more wellbore valves 200 installed along the length of the tubing 100. Each of the wellbore valves 200 is placed in one of the well sections 110. The wellbore valve 200 in each well section 110 allows a reservoir section 112 adjacent to the well section 110 to be stimulated or produced. The wellbore valve 200 also prevents particles, such as propping material, from the reservoir section 112 or well 102 from flowing into the tubing 100 with reservoir fluids.

[0029] In FIG. 2A, an embodiment of the wellbore valve 200 includes a valve body 201. A screen 202 is mounted on and about a circumference of the valve body 201. An outer conduit 206 is defined between the screen 202 and an opposing outer surface 208 of the valve body 201. One or more inlet ports 210 are formed in the valve body 201 at a location above the outer conduit 206. The inlet ports 210 are distributed along a circumference of the valve body 201 and are connected to the outer conduit 206 via internal conduits 212. A check valve 214 is arranged in each internal conduit 212 to control flow between a respective inlet port 210 and the outer conduit 206. Each inlet port 210 includes a fixed or autonomous choke 215. A fixed choke is a flow-through port of a predetermined dimension. An autonomous choke is a self-regulating choke that is preset to maintain a predetermined flow- through rate even if pressure before or after the choke changes. An exemplary autonomous choke is disclosed in International Patent Publication WO

2009/136796A1 (published 12 November 2009; Bernt Sigve AADN0Y).

[0030] Also, one or more outlet ports 216 are formed in the valve body 201 at a location above the inlet ports 210. The outlet ports 216 are distributed along a circumference of the valve body 201. The valve body 201 includes an axial bore 218. When the wellbore valve 200 is installed on the tubing 100 (in FIG. 1), the axial bore 218 is aligned with and in communication with the axial bore of the tubing 100. The inlet ports 210 and outlet ports 216 are connected to the axial bore 218. A sleeve 220 is arranged in the axial bore 218 and can be moved along the axial bore 218 to open or close the inlet ports 210 and outlet ports 216. A spring 222 is arranged between an inner shoulder 224 of the valve body 201 and the sleeve 220 to normally urge the sleeve 220 upwardly to cover the outlet ports 216, leaving the inlet ports 210 open. The outlet ports 216 can be opened, and the inlet ports 210 closed, by pushing the sleeve 220 against the spring 222. The sleeve 220 includes an internal machined profile 226 configured to engage a matching profile on a tool, such as an intervention tool or a dart.

[0031] Reservoir fluid can flow into the outer conduit 206 through the screen 202. The screen 202 would keep particles, such as propping material, from flowing into the outer conduit 206. The pore size of the screen 202 dictates the sizes of particles that are prevented from entering the outer conduit 206. The reservoir fluid entering the outer conduit 206 can flow into the inlet ports 210 through the check valves 214. The check valves 214 are arranged to allow flow only from the outer conduit 206 to the inlet ports 210. The fixed or autonomous choke 215 in each of the inlet ports 210 controls flow of the reservoir fluid into the axial bore 218. When the inlet ports 210 are opened up to the axial bore 218, the outlet ports 216 are closed off from the axial bore 218. The outlet ports 216 can be opened up to the axial bore 218, and the inlet ports 210 closed off from the axial bore 218, to allow a stimulation fluid to be pumped through the axial bore 218 and outlet ports 216 into a formation zone.

When pumping of the stimulation fluid into the formation zone is no longer desired, the outlet ports 216 can be closed again, and the inlet ports 210 can be opened again.

[0032] In FIG. 2B, a method of opening the outlet ports 216 by pumping a ball 228 against the sleeve 220 is shown. The ball 228, which is made of a hard material such as steel, is first dropped into the axial bore 218 so that it lands on the sleeve 220. Then, fluid is pumped into the axial bore 218 to force the ball 228 against the sleeve 220. The pressure of the fluid pumped into the axial bore 218 is increased until it overcomes the force of the spring 222 and pushes the sleeve 220 downwardly to open the outlet ports 216 and simultaneously close the inlet ports 210. In FIG. 2C, the same method of opening the outlet ports 216 with a ball 228 is shown. The difference between FIGS. 2C and 2B appears in the sleeve 230, which replaces previous sleeve 220 (in FIG. 2B). Sleeve 230 includes a seat 232 for the ball 228. The sleeve 230 may be manufactured such that the seat 232 can be easily drilled or milled out after stimulation of all the reservoir sections is completed. One reason for removing the seat 232 would be to prevent the seat 232 from creating a choking effect due to its diameter being smaller than that of the axial bore 218 of the valve body 201. In FIG. 2D, a method of opening the outlet ports 216 by pumping a dart 234 against the sleeve 236 is shown. The sleeve 236 replaces the previous sleeve 220 (in FIG. 2B) and includes an internal machined profile 238 that engages with a matching profile 240 on the dart 234.

[0033] In FIG. 2A, the ball 228 (in FIG. 2B or 2C) or dart 234 (in FIG. 2D) has been removed from the axial bore 218. In one embodiment, the ball 228 or dart 234 is removed by retrieving it to the surface. In another embodiment, the ball 228 or dart 234 is removed by dissolving it. Removing the ball 228 or dart 234 closes the outlet ports 216 and opens the inlet ports 210. The outlet ports 216 will also close, and the inlet ports 210 will open, by stopping pumping of fluid into the axial bore 218, i.e., without also removing the ball 228 or dart 234. However, to allow flow of fluid through the axial bore 218, such as reservoir fluid from the inlet ports 210, it would be necessary to remove the ball 228 or dart 234 as described above. When the inlet ports 210 are open, reservoir fluids can flow into the axial bore 218 via the screen 202, outer conduit 206, internal conduits 212, and inlet ports 210. The screen 202 filters the reservoir fluids flowing into the axial bore 218 as previously explained.

[0034] A general procedure for stimulating the various formation zones 112 (in FIG. 1) of the well 102 (in FIG. 1) includes installing the well completion 101 (in FIG. 1) in the well 102. To allow the formation zones 112 to be stimulated

individually, the sleeves 202 (in FIG. 2A) of the wellbore valves 200 may be individualized. For example, the sleeve 202 of each of the wellbore valves 200 may be configured to engage a ball or dart having a specific characteristic so that when the ball or dart having that specific characteristic is pumped down the tubing 100 (in FIG. 1) only the desired wellbore valve 200 will be opened for stimulation.

Stimulation is done by first opening up the outlet ports 216 (in FIG. 2B) of the wellbore valve 200 adjacent to a desired formation zone 112. Then, fluid, e.g., water, is pumped at high pressure into the desired formation zone 112 through the outlet ports 216. The pumped fluid will create cracks or fractures in the formation that will enable reservoir fluids to flow back into the well 102. The fluid pumped into the formation zone 112 can contain propping material, such as proppants and/or sand. The propping material is packed into the fractures so that the fractures do not collapse when the fluid injection pressure is reduced to the reservoir pressure. After stimulation is completed, the outlet ports 216 are closed and the inlet ports 210 (in FIG. 2A) are opened. Reservoir fluids can then flow into the tubing 100 via the inlet ports 210. The screen 202 (in FIG. 2A) will prevent particles, such as propping material, from entering the tubing 100 with the reservoir fluids.

[0035] In FIG. 3A, a wellbore valve 300 that can be fully closed, e.g., in the case of unwanted water or gas breakthrough, is shown. The wellbore valve 300 can replace the wellbore valve 200 (in FIG. 1). The wellbore valve 300 differs from the wellbore valve 200 (in FIG. 2 A) in certain details about the valve body 301, the sleeve 320, and the spring 322. The valve body 301 includes a surface 342 that acts as an upper stop for the sleeve 320. The sleeve 320 includes openings 344, which may be selectively aligned with the inlet ports 310 in the valve body 301. The spring 322 is arranged between the inner shoulder 324 and the sleeve 320. The spring 322 is selected such that under normal (producing) conditions the sleeve 320 closes off the outlet ports 316 and the openings 344 are aligned with the inlet ports 310. Under these normal conditions, reservoir fluids can flow into the axial bore 318 through the screen 302, the outer conduit 306, the internal conduits 314, the inlet ports 310, and the openings 344. Also, under these normal conditions, the sleeve 320 is restricted from abutting the surface or upper stop 342. The outlet ports 316 can be opened and the inlet ports 310 closed by pumping a ball 328 or dart into the sleeve 320, as shown in FIG. 3B and as described for the wellbore valve 200 (in FIG. 3B or 3C or 3D).

[0036] To close both the inlet ports 310 and outlet ports 316, the sleeve 320 has to be moved upwardly until it abuts the surface or upper stop 324, as shown in FIG. 3C. An intervention tool is used to move the valve to the fully closed position, i.e., when both the inlet and outlet ports 310, 316 are closed. In FIG. 3D, there is a small shoulder 346 on the inner surface 348 of the valve body 301 that the sleeve 320 must overcome before it can reach and abut the surface or upper stop 324. The intervention tool is used to provide the necessary force to move the sleeve 320 past the shoulder 346. The intervention tool would lock into the sleeve 320 and will then be pulled towards the surface or upper stop 324 until the sleeve 320 abuts the surface or upper stop 324. Friction between the sleeve 320 and the valve body 301 can keep the sleeve 320 in place once the wellbore valve 300 is in this fully closed position. Alternatively, shear pins could be implemented in the sleeve 320 to lock the sleeve 320 in place once the wellbore valve 300 is in this fully closed position. The shear pins could be magnetic and/or spring-loaded. The shear pins will be sheared when it is desired to bring the wellbore valve 300 to the fully open position again. Shearing of the shear pins may involve jarring down on the sleeve 320 until the shear pins break. The same jarring down on the sleeve 320 may be used if the sleeve 320 is held in place by friction.

[0037] In FIG. 4A, a wellbore valve 400 for controlling production from a multi- zone well where so-called "huff-n-puf ' steam treatments are performed is shown. A "huff- n- puff ' steam treatment involves injecting steam from the surface into a production reservoir for a period of time, leaving the well shut in for another period of time to allow soaking of the formation, and then producing the well until steam injection is again required. The temperature of the steam allows the oil to become less viscous, providing easier production through the rock formation. The wellbore valve 400 is similar to the wellbore valve 200 (in FIG. 2A) in many respects.

However, the wellbore valve 400 does not include a sleeve for selectively opening and closing ports. The wellbore valve 400 includes a valve body 401, a screen 402 mounted on and about a circumference of the valve body 401, and an outer conduit 406 defined between the screen 402 and an opposing outer surface 408 of the valve body 401. One or more inlet ports 410 are formed in the valve body 401 at a location above the outer conduit 406. The inlet ports 410 are distributed along a

circumference of the valve body 401 and are connected to the conduit 410 via internal conduits 412. A check valve 414 is arranged in each internal conduit 414 to control flow between a respective inlet port 410 and the outer conduit 406. Each inlet port 410 includes a fixed or autonomous choke 415. Also, one or more outlet ports 416 are formed in the valve body 401 at a location above the inlet ports 410. The outlet ports 416 are distributed along a circumference of the valve body 401.

[0038] A check valve 417 is incorporated in each outlet port 416. The check valve 417 may be a spring-loaded check valve as shown in FIG. 4A or a check valve using a pin, as shown at 419 in FIG. 4B. In the case of the check valve 419 using a pin 419a, the pin 419a prevents the ball 419b of the check valve 419 from being pumped out of its recessed pocket 419c. Flow back through the check valve 419 from the outside of the wellbore valve 400 will push the ball 419b back into its seat 419d, where the ball 419b will seal off the outlet port 416. The ball 419b can be made of a lightweight material so that it is easier to push the ball back into its seat by the flow back. In another embodiment, as shown in FIG. 4C, a flapper valve 421 may be incorporated in each outlet port 416 instead of a check valve. The flapper valve 421 would allow fluid flow through the outlet port 416 in one direction, i.e., from the inside to the outside of the wellbore valve 400. The valve body 401 includes an axial bore 418, which in use may be aligned with the axial bore of a tubing. Wellbore valve 400 allows steam received in the axial bore 418 to be injected into a formation zone through the outlet ports 416. At the same time, valve 400 allows fluids from the formation zone to be received in the axial bore 418. The fluid flow into the axial bore 418 occurs through a preset choke and pressure differential provided by the fixed or autonomous choke 415.

[0039] In FIG. 5, a well 500 traverses two formation zones 502, 504. Two tubings 506, 508 are arranged in the well 500 for production. The tubing 506 is associated with the formation zone 502 and is used to produce reservoir fluids from or inject fluids into the formation zone 502. The tubing 508 is associated with the formation zone 504 and is used to produce reservoir fluids from or inject fluids into the formation zone 504. The dedicated tubings 506, 508 make it possible to determine and know the contribution of each of the formation zones 502, 504 to the total production. Zonal isolation devices 510, 512 are used to isolate the formation zones 502, 504 from each other. The zonal isolation device 510 seals between the tubing 504 and the wall 514 of the well 500. The zonal isolation device 512 seals between the tubings 506, 508, between the tubing 506 and the wall 514 of the well 500, and between the tubing 508 and the wall 514 of the well 500. A perforated liner 516 is disposed in the well 500, adjacent to the formation zones 502, 504. The perforated liner 516 maintains the integrity of the well 500, and the perforations in the perforated liner 516 allow reservoir fluids to enter into the well 500. Plugs 520, 522 are disposed at the bottom ends of the tubings 506, 508, respectively, to seal the bottom ends of the tubings 506, 508. Wellbore valves 524, 526 are disposed on the tubings 506, 508, respectively. The wellbore valves 524, 526 may be any of the wellbore valves described above and shown in FIGS. 1-4C. The wellbore valves 524, 526 allow fluid to enter the tubings 506, 508 while providing the particle screening functionality described above.

[0040] While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.

Claims

1. A wellbore valve, comprising:

a valve body having an inlet port, an outlet port, and an axial bore;

a screen mounted on the valve body and positioned in a flow path between an exterior of the valve body and the inlet port for filtering a fluid flowing into the inlet port along the flow path; and

a valve member disposed in the axial bore, the valve member being movable relative to the valve body between a first valve position where the valve member opens up the inlet port to the axial bore and closes off the outlet port from the axial bore and a second valve position where the valve member closes off the inlet port from the axial bore and opens up the outlet port to the axial bore.

2. A wellbore valve according to claim 1, wherein the inlet port includes a choke.

3. A wellbore valve according to claim 1, wherein the outlet port includes a oneway valve.

4. A wellbore valve according to claim 1, wherein the valve member is spring- loaded and a change from the first valve position to the second valve position includes overcoming a spring load.

5. A wellbore valve according to claim 1, wherein the valve member has a

surface for engaging a ball or a dart.

6. A wellbore valve according to claim 1, wherein the valve member has a

profiled surface for engagement with a matching profiled surface on an external tool.

7. A wellbore valve according to claim 1, wherein the valve member is movable to a third valve position where the valve member closes off both the inlet port and the outlet port from the axial bore.

8. A wellbore valve according to claim 7, further comprising an obstruction on the valve body that the valve member overcomes prior to moving to the third valve position.

9. A wellbore valve according to claim 1, further comprising a one-way valve in the flow path, the one-way valve being configured to permit flow in a direction from the exterior of the valve body to the inlet port.

10. A wellbore valve, comprising:

a valve body having an inlet port including a choke, an outlet port including a one-way valve, and an axial bore in communication with the inlet port and outlet port; and

a screen mounted on the valve body and positioned in a flow path between an exterior of the valve body and the inlet port for filtering a fluid flowing into the inlet port along the flow path.

11. The wellbore valve of claim 10, further comprising a one-way valve in the flow path, the one-way valve being configured to permit flow in a direction from the exterior of the valve body to the inlet port.

12. A wellbore system, comprising:

at least one wellbore valve disposed in the well, the at least one wellbore valve having an inlet port, an outlet port, a valve member movable between a first valve position where the valve member opens up the inlet port and closes off the outlet port and a second valve position where the valve member closes off the inlet port and opens up the outlet port, and a screen in a flow path between an exterior of the at least one wellbore valve and the inlet port for filtering a fluid flowing into the inlet port along the flow path; and

at least one zonal isolation device disposed in the well for isolating a

formation zone traversed by the well.

13. The wellbore system of claim 12, further comprising a tubing disposed in the well, wherein the at least one wellbore valve is disposed on the tubing and controls fluid flow between the tubing and the well.

14. The wellbore system of claim 12, further comprising a one-way valve in the flow path, the one-way valve being configured to permit flow in a direction from the exterior of the at least one wellbore valve to the inlet port.

15. A method of producing fluids from a well, comprising:

(a) installing at least one wellbore valve in the well, the at least one wellbore valve having an inlet port, an outlet port, a valve member movable between a first valve position where the valve member opens up the inlet port and closes off the outlet port and a second valve position where the valve member closes off the inlet port and opens up the outlet port, and a screen in a flow path between an exterior of the at least one wellbore valve and the inlet port for filtering a fluid flowing into the inlet port along the flow path; and

(b) moving the valve member to the first valve position to allow a fluid from a formation traversed by the well to flow into the inlet port through the flow path.

16. A method according to claim 15, further comprising:

(c) moving the valve member to the second valve position to open the outlet port; and

(d) injecting a stimulation fluid into the formation through the outlet port.

17. A method according to claim 16, wherein steps (c) and (d) precede step (b).

18. A method according to claim 17, wherein step (c) comprises pumping a ball or a dart and fluid into the at least one wellbore valve to move the valve member.

19. A method according to claim 18, wherein step (b) comprises stopping pumping of the fluid into the at least one wellbore valve and removing the ball or dart from the at least one wellbore valve.

20. A method according to claim 15, wherein step (a) comprises installing a

plurality of wellbore valves in the well such that each of the wellbore valves is adjacent to a formation zone traversed by the well.

21. A method according to claim 20, further comprising:

(e) stimulating a selected formation zone traversed by the well using one of the wellbore valves adjacent to the selected formation zone.

22. A wellbore system, comprising:

a first tubing disposed in a well traversing a first formation zone and a

second formation zone, the first tubing being hydraulically connected to the first formation zone;

a second tubing disposed in the well, the second tubing being hydraulically connected to the second formation zone;

at least one zonal isolation device for isolating the first formation zone from the second formation zone; and

at least one wellbore valve disposed along at least one of the first and second tubings, the at least one wellbore valve having an inlet port, an outlet port, a valve member movable between a first valve position where the valve member opens up the inlet port and closes off the outlet port and a second valve position where the valve member closes off the inlet port and opens up the outlet port, and a screen in a flow path between an exterior of the at least one wellbore valve and the inlet port for filtering a fluid flowing into the inlet port along the flow path.