Apparatus and method for stimulating subterranean formations

Abstract

A method of stimulating a subterranean formation using a tubular member with one or more burst disks therein.

Claims

1. A pressure equalization valve for a treatment tool movable in a completion string, a space being formed between the treatment tool and the completion string above an isolation device, the valve comprising: a cylindrical valve body having an axial bore in fluid communication with the treatment tool, a valve opening between the axial bore and the completion string below the isolation device, and one or more fluid ports above the valve opening between the axial bore and the space; a cylindrical shuttle axially and sealably movable in the axial bore and having an uphole portion and a downhole portion having the same diameter; one or more diverter flow ports adjacent the shuttle's uphole portion and formed between the axial bore of the valve body and the space, wherein the shuttle is operable between a closed position, the shuttle's downhole portion blocking the valve opening for blocking fluid flow through the one or more fluid ports between the space and the completion string below the isolation device, and an open position, the shuttle's downhole portion spaced from the valve opening for fluid communication between the space and the valve opening, fluid flowing from the treatment tool above, through the axial bore, diverting by the shuttle's uphole portion through the one or more diverter flow ports, flowing through the space, through the one or more flow ports and through the valve opening to the completion string below the isolation device; and a spring acting between the shuttle and the valve body for normally biasing the shuttle to the open position, wherein, when a flow rate of the fluid flowing from the treatment tool exceeds a preset rate to overcome the spring biasing, the shuttle shifts to the closed position, retaining the fluid flow in the space; and when the flow rate from the treatment tool drops below the preset rate, the spring biases the shuttle to the open position for equalizing the pressure above and below the isolation device.

2. The pressure equalization valve of claim 1 further comprising a valve seat at the valve opening, the downhole portion seating in the valve seat.

3. The pressure equalization valve of claim 2 wherein the shuttle's downhole portion is a hardened needle and the valve seat is a hardened valve seat.

4. The pressure equalization valve of claim 1, further comprising: at least an upper seal between the axial bore and the shuttle's uphole portion, and wherein, the axial bore is fit with a stop intermediate the valve opening and the upper seal, and the shuttle is fit with a shoulder intermediate the shuttle's uphole and downhole portions and uphole of the stop, and wherein the spring is located between the stop and the shoulder.

5. The pressure equalization valve of claim 4, further comprising: a lower seal between the axial bore and the shuttle's downhole portion.

6. The pressure equalization valve of claim 1, wherein the shuttle's uphole portion is bell-like for diverting fluid flow through the diverter flow ports.

7. The pressure equalization valve of claim 1, wherein the valve body further comprises drain flow ports below the isolation device for draining fluid from the valve opening to the completion string.

8. The pressure equalization valve of claim 1 wherein the treatment tool is a well treatment tool.

9. The pressure equalization valve of claim 8 wherein the well treatment tool is a fracturing tool.

10. The pressure equalization valve of claim 8 wherein the well treatment tool is a fracturing tool wherein the isolation device is at least two isolation devices forming the space therebetween, the fracturing tool further comprising: a fluid ejection opening straddled by the at least two isolation devices.

11. The pressure equalization valve of claim 1 wherein the isolation device is a cup.

12. The pressure equalization valve of claim 1 wherein the isolation device is a packer.

13. A pressure equalization valve for a treatment tool movable in a completion string, a space being formed between the treatment tool and the completion string above an isolation device, the valve comprising: a cylindrical valve body having an axial bore in fluid communication with the treatment tool, a valve opening between the axial bore and the completion string below the isolation device, and one or more fluid ports above the valve opening between the axial bore and the space; a cylindrical shuttle axially and sealably movable in the axial bore and having an uphole bell-like portion for diverting fluid flow through the diverter flow ports and a downhole portion having the same diameter; one or more diverter flow ports adjacent the shuttle's uphole portion and formed between the axial bore of the valve body and the space, wherein the shuttle is operable between a closed position, the shuttle's downhole portion blocking the valve opening for blocking fluid flow through the one or more fluid ports between the space and the completion string below the isolation device, and an open position, the shuttle's downhole portion spaced from the valve opening for fluid communication between the space and the valve opening, fluid flowing from the treatment tool above, through the axial bore, diverting by the shuttle's uphole portion through the one or more diverter flow ports, flowing through the space, through the one or more flow ports and through the valve opening to the completion string below the isolation device; at least an upper seal between the axial bore and the shuttle's uphole portion; a stop fit in the axial bore intermediate the valve opening and the upper seal; a shoulder fit in the shuttle intermediate the shuttle's uphole and downhole portions and uphole of the stop in the axial bore; and a spring located between the stop and the shoulder and acting between the shuttle and the valve body for normally biasing the shuttle to the open position, wherein, when a flow rate of the fluid flowing from the treatment tool exceeds a preset rate to overcome the spring biasing, the shuttle shifts to the closed position, retaining the fluid flow in the space; and when the flow rate from the treatment tool drops below the preset rate, the spring biases the shuttle to the open position for equalizing the pressure above and below the isolation device.

14. The pressure equalization valve of claim 13, further comprising: a lower seal between the axial bore and the shuttle's downhole portion.

15. A pressure equalization valve for a fracturing tool movable in a completion string, a space being formed between the fracturing tool and the completion string above at least two isolation devices forming the space therebetween and straddling a fluid ejection opening in the fracturing tool, the valve comprising: a cylindrical valve body having an axial bore in fluid communication with the treatment tool, a valve opening between the axial bore and the completion string below the isolation device, and one or more fluid ports above the valve opening between the axial bore and the space; a cylindrical shuttle axially and sealably movable in the axial bore and having an uphole portion and a downhole portion having the same diameter; one or more diverter flow ports adjacent the shuttle's uphole portion and formed between the axial bore of the valve body and the space, wherein the shuttle is operable between a closed position, the shuttle's downhole portion blocking the valve opening for blocking fluid flow through the one or more fluid ports between the space and the completion string below the isolation device, and an open position, the shuttle's downhole portion spaced from the valve opening for fluid communication between the space and the valve opening, fluid flowing from the treatment tool above, through the axial bore, diverting by the shuttle's uphole portion through the one or more diverter flow ports, flowing through the space, through the one or more flow ports and through the valve opening to the completion string below the isolation device; at least an upper seal between the axial bore and the shuttle's uphole portion; a stop fit in the axial bore intermediate the valve opening and the upper seal; a shoulder fit in the shuttle intermediate the shuttle's uphole and downhole portions and uphole of the stop in the axial bore; and a spring located between the stop and the shoulder and acting between the shuttle and the valve body for normally biasing the shuttle to the open position, wherein, when a flow rate of the fluid flowing from the treatment tool exceeds a preset rate to overcome the spring biasing, the shuttle shifts to the closed position, retaining the fluid flow in the space; and when the flow rate from the treatment tool drops below the preset rate, the spring biases the shuttle to the open position for equalizing the pressure above and below the isolation device.

16. The pressure equalization valve of claim 15, further comprising: a lower seal between the axial bore and the shuttle's downhole portion.

17. The pressure equalization valve of claim 15 wherein the well treatment tool is a fracturing tool.

18. The pressure equalization valve of claim 15 wherein the isolation device is a cup.

19. The pressure equalization valve of claim 15 wherein the isolation device is a packer.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) FIG. 1A is a drawing of a cross-section of a wellbore and a completion string having burst disks in accordance with one embodiment of this invention;

(2) FIG. 1B is a drawing of the cross-section of the wellbore and completion string of FIG. 1A with a treatment tubing and tool inserted therein positioned at a first zone;

(3) FIG. 1C is a detail of section A of the cross-section of the wellbore and completion string of FIG. 1B with fluid pumped down the treatment tubing;

(4) FIG. 1D is a drawing of the cross-section of the wellbore and completion string of FIG. 1C with fluid flowing from the treatment tubing and out the ruptured burst disks;

(5) FIG. 1E is a drawing of the cross-section of the wellbore and completion string of FIG. 1A with the tool re-positioned at a second zone;

(6) FIG. 1F is a drawing of the cross-section of the wellbore and completion string of FIG. 1E with fluid pumped down the treatment tubing;

(7) FIG. 1G is a drawing of the cross-section of the wellbore and completion string of FIG. 1E with ruptured burst disks;

(8) FIG. 2A is a drawing of a partial cross-section of a completion string without a tool therein in accordance with one embodiment of this invention;

(9) FIG. 2B is a cross-section Detail A of FIG. 2A showing a burst disk in place in a completion string according to one embodiment of this invention;

(10) FIG. 2C is a cross-section Detail B of FIG. 2D showing a ruptured burst disk according to one embodiment of this invention;

(11) FIG. 2D is a drawing of a partial cross-section of a completion string with a tool therein in accordance with one embodiment of this invention;

(12) FIG. 3 is a drawing of a cut-away perspective view of a wall of a completion string with a burst disk in accordance with one embodiment of this invention;

(13) FIG. 4A is a drawing of an end cross section view of a completion string having a burst disk in accordance with one embodiment of this invention;

(14) FIG. 4B is a drawing of a cross-sectional view of the completion string taken along the line A-A in FIG. 4A;

(15) FIG. 5A is a drawing of a cross-sectional view of a wellbore and completion string having burst disks in a collar according to one embodiment of this invention;

(16) FIG. 5B is a detailed cross-sectional view of the burst disk of FIG. 5A;

(17) FIG. 6A is a drawing of the cross-section of an enlarged portion of the wellbore and completion string of FIG. 1B with fluid pumping down the treatment tubing;

(18) FIG. 6B is a drawing of the cross-section of the wellbore and completion string of FIG. 6A with the tool re-positioned downhole;

(19) FIG. 6C is a drawing of the cross-section of the wellbore and completion string of FIG. 6A with fluid flowing from an annulus and out the ruptured burst disks;

(20) FIG. 6D is a drawing of the cross-section of the wellbore and completion string of FIG. 1A with the tool re-positioned uphole at a second zone;

(21) FIG. 6E is a drawing of the cross-section of an enlarged portion of the wellbore and completion string of FIG. 6D with fluid pumping down the treatment tubing;

(22) FIG. 6F is a drawing of the cross-section of the wellbore and completion string of FIG. 6D with the tool re-positioned downhole from the second zone;

(23) FIG. 6G is a drawing of the cross-section of the wellbore and completion string of FIG. 6D with fluid flowing from an annulus and out the ruptured burst disks at the second zone;

(24) FIG. 7A is a drawing of a cross-section of a wellbore and a completion string having burst disks in accordance with another embodiment of this invention;

(25) FIG. 7B is a drawing of a cross-section of a wellbore and a completion string of FIG. 7A with fluid pumping down the completion string and burst disks ruptured;

(26) FIG. 8A is a drawing of a cross-section of a wellbore and a completion string having burst disks in accordance with another embodiment of this invention;

(27) FIG. 8B is a drawing of a cross-section of a wellbore and a completion string of FIG. 8A with fluid pumping down the completion string and burst disks at a first zone ruptured;

(28) FIG. 8C is a drawing of a cross-section of a wellbore and a completion string of FIG. 8A with a sealing device uphole from the first zone;

(29) FIG. 8D is a drawing of a cross-section of a wellbore and a completion string of FIG. 8A with fluid pumped down the treatment tubing burst disks at a second zone ruptured;

(30) FIG. 8E is a drawing of a cross-section of a wellbore and a completion string of FIG. 8A with a sealing device uphole from the second zone;

(31) FIG. 9A is a drawing of a cross-section of a wellbore and a completion string with frac balls pumping down the completion string and sealing ruptured burst disks at a first zone according to one embodiment of this invention;

(32) FIG. 9B is a drawing of a cross-section of a wellbore and a completion string of FIG. 9A with fluid pumping down the completion string and burst disks at a second zone ruptured;

(33) FIG. 9C is a drawing of a cross-section of a wellbore and a completion string of FIG. 9A with frac balls pumping down the completion string and sealing ruptured burst disks at a second zone;

(34) FIG. 10A is a partial cross-sectional view of a burst disk assembly in a collar cemented to a wellbore according to another embodiment of this invention;

(35) FIG. 10B is a partial cross-sectional view of the burst disk assembly in FIG. 10A having a ruptured burst disk;

(36) FIG. 10C is a partial cross-sectional view of the burst disk assembly in FIG. 10A with an unsecured cap;

(37) FIG. 10D is a partial cross-sectional view of the burst disk assembly in FIG. 10A that has ruptured through the cement;

(38) FIG. 10E is a partial cross-sectional view of the burst disk assembly in FIG. 10A that has ruptured through a formation;

(39) FIG. 11A is a cross-section of a frac tool pressure equalization valve according to one embodiment of this invention;

(40) FIG. 11B is a cross-section of the valve of FIG. 11A taken along the line A-A;

(41) FIG. 11C is a front view of the valve of FIG. 11A taken along the line B-B;

(42) FIG. 11D is an enlarged view of section C in FIG. 11B;

(43) FIG. 12A is a collar according to one embodiment of this invention;

(44) FIG. 12B is a collar according to another embodiment of this invention;

(45) FIG. 13A is a partial cross-section of a wellbore and a completion string in accordance with an embodiment of this invention;

(46) FIG. 13B is a partial cross-section of a wellbore with a completion string and a downhole tool in accordance with an embodiment of this invention;

(47) FIG. 14 is a cross section of a wellbore and treatment string with an isolation device; and

(48) FIG. 15 is a cross-section of a sliding sleeve according to one embodiment of this invention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

(49) In general, apparatus and methods of this invention can be applied to a horizontal, deviated or vertical open hole completion or cemented condition, or a frac through coil system where a multi-stage cased/open hole hybrid system is used where isolation and frac points are set up along an open hole section of a well to give full bore access to the wellbore casing string at the completion of the stimulation.

(50) Referring to FIGS. 1A to 1F, in a sequence of steps in stimulating a formation according to one embodiment of this invention, a section of a wellbore 10 is drilled through the earth 2 having a subterranean hydrocarbon bearing formation 3. The wellbore 10 is a horizontal well. Within the wellbore 10 is a completion string 12.

(51) A completion string is usually a tubular pipe also commonly known as production casing or well bore liner that is usually permanently installed in the well bore. A completion string may be a wellbore casing, liner, tubulars or any other similar tubing.

(52) The completion string 12 is in what is commonly known as open hole condition, meaning that the annular space 18 between completion string 12 and the wellbore 10 is not purposely filled.

(53) Segments of a completion string can be joined together with collars. The completion string 12 includes collars 40 that join sections 13 of the completion string 12 together. The collars 40 are equally spaced but need not be equally spaced along the completion string 12 and are usually placed at intervals determined by the conditions of the hydrocarbon bearing formation and the results desired from the stimulation process.

(54) The collars 40 of the completion string 12 include burst disks which are housed in burst ports 20 of the collars 40. In general, a burst disk is a device which is designed to rupture once a certain pressure threshold is reached thus opening a port in the wall in which it is located.

(55) Burst disks embodying the principles of this invention can be located within different types of bodies. For example, the body can be a completion string or like tubing or piping, or a collar. A “collar” is a tubular section of larger outside diameter and shorter length than the adjacent tubular sections that comprise the majority of a drill string. Often collars are used to join tubular sections together, and as such may have any combination of thread types on their ends. Collars may also serve functions other than simply extending the drill string or joining sections of tubulars together. Burst disks can also be located in the walls of a completion string. Bodies, including completion strings, drill strings, and treatment strings, tubulars, tubing, piping and collars are also referred to herein as tubular members.

(56) A treatment string is usually a tubular pipe for conveying fluids, such as but not limited to coiled tubing and collars, for conveying fluids, that is not permanently installed in a well bore. Treatment tubing is commonly inserted into a wellbore (in either an open hole or completed state) to convey fluid into and/or out of the wellbore to for example, stimulate a subterranean formation. It is also known to attach a bottom hole (“BHA”) device to treatment tubing where the treatment tubing can be used to insert and/or remove the BHA and convey fluid to operate the BHA.

(57) One embodiment of a collar suitable for the invention in which burst disks can be placed is shown in FIG. 12A. The collar indicated generally at 41 includes a central section 42. Burst disk assemblies 22 are housed in ports 20 in the central section 42 of the collar 41.

(58) Another embodiment of a collar suitable for the invention in which burst disk assemblies 22 can be placed is shown in FIG. 12B. The collar indicated generally at 43 is a collar with a central section 44. Fins 100 protrude outwardly from the wall of the collar 43 thereby decreasing the space between collar 43 and a wellbore when installed.

(59) Referring principally to FIGS. 10A, 12A, 12B, and 14A to 14G, the burst disk assembly 22 comprises a retainer 140, which in turn threads into the wall 400. If the burst disk assembly 22 is housed in a collar of the type of the collar 41, the wall 400 forms part of the central section 42. Alternatively, if the burst disk assembly 22 is housed in a collar of the type of collar 43, the wall 400 forms part of one of the fins 100. The retainer 140 is threaded into the wall 400 by threads 153 to hold the burstable disk 148 in place. O rings 155 are provided between the wall 400 and the retainer 140 and the burstable disk 148. A cap 150 fits into retainer 140 such that a pressure tight seal is formed between the central conduit of a completion string and the outside of the completion string whether it is inside a wellbore or outside. The cap 150 is covered with a protective mastic 152, such as silicone sealant to protect it during shipping and handling, and to help retain it in place. The chamber 157 formed between the burst disk and the cap 150 normally contains air, but may be filled with other fluids, depending upon the operational circumstances.

(60) The cap 150 prevents pressure on the outside of a completion string or collar from bursting the burstable disk 148 from the outside of the string or collar inward during the placement, servicing, or cementing of the collar or completion string in which it is housed. The chamber 157 is normally close to atmospheric pressure until the burstable disk 148 bursts. The atmospheric pressure facilitates the bursting of the burstable disk 148 at a predictable pressure, as the necessary pressure acting inside the collar and against the interior side of the disk can be determined in a reliable manner. The burstable disk 148 in a burst condition is depicted in FIGS. 10b to 10e. Once the burstable disk 148 is ruptured, the cap 150 is displaced toward the wellbore, or otherwise removed, by the fluids F flowing through the chamber 157 for permitting the fluids F to flow therethrough to the wellbore.

(61) Referring principally to FIGS. 2A to 4B, in an alternate embodiment, a burst disk assembly embodying the principles of the present invention may be formed by machining the sidewall of a collar or any portion of a wall of a completion string to produce a thin section which serves as a burstable disk. Alternatively, the burstable disk may be a thin sheet of material with properties such that it will rupture at the desired pressure differential across it.

(62) The burstable disk 20a is made from the same material as the wall 401 of the completion string or collar in which it is formed.

(63) The burstable disk 20a can be circular in shape. In one embodiment, the burstable disk 20a has a diameter between ¼ inch and 1 inch when used with a completion string of suitable material and thickness. More preferably, the diameter is 7/16 inches or ⅝ inches. However, a person of ordinary skill in the art would understand that the shape, thickness and diameter of the burst disk may vary.

(64) The thickness of the remaining wall defining the burst disk, the diameter of the burstable disk 20a, and the material of the burst disk will determine the magnitude of burst pressure. For example, according to one embodiment, a burstable disk diameter of about ⅝ inches and a burstable disk wall casing thickness of 0.01 inches results in a burst pressure of about 3,000 psi to about 4,000 psi using L-80 casing.

(65) The burstable disk is preferably made of type 302 stainless steel, however the burst disk can be made of any suitable material that could withstand the pressures described in this invention. For example, the burst disk can be made of plastic or other metals such as an alloy, stainless steel or other suitable material that can withstand the design pressures, or a material that dissolves upon contact with a dissolving fluid. An example of a dissolving fluid is an acid.

(66) A person of ordinary skill in the art would understand that the shape and size of the burst disk and the port in which it is placed may vary.

(67) FIGS. 2A and 2D show a cross section of the wellbore 10 lined with a completion string 12. FIG. 2D depicts a well treatment tool indicated generally at 600 positioned within the completion string 12. In another embodiment of this invention, the burst disks 20a are formed from the wall of the completion string 12. At intervals along the length of the completion string 12, the wall is thinned at certain points by machining. Preferably, the points are formed radially on the circumference of the tube 12. However, the points can be arranged in any other desired pattern. In one embodiment, the thickness of the thinned wall section is 0.01 inches but the thickness of the wall can vary depending upon the materials used and the desired burst pressure. This is achieved by boring partway through the wall of the completion string to create a port 16 having a burstable disk 20a as a base. Each thinned wall section defines a burstable disk. More preferably, the port 16 is counter-bored.

(68) FIG. 3 shows a partial-section of the port 16 in the wall 401 of a completion string such as completion sting 12 where the burstable disk 20a is formed integrally with the completion string. The wall of the burstable disk 12a of the completion string 12 is preferably counter-bored such that a counter-bore of greater diameter extends approximately half-way through the wall of the treatment tube, and a second bore of smaller diameter is made within the first bore to create a thinned wall section forming the burstable disk 20a. Preferably, the bores are made perpendicular to the longitudinal wall of the completion string, however this is not necessary. A person of ordinary skill in the art would appreciate that the order of boring the bore and counter-bore does not matter. The bore does not penetrate through the wall of the burstable disk 12a. Between the protective cover 14 and the thinned wall of the burstable disk 20a is a space at atmospheric pressure.

(69) As shown in FIG. 3, a protective cover 14 is preferably peened in place to entirely cover the area of the port 16. The cover 14 may be held in place by other means. For example, the cover 14 can be press fit or held in place by means of an O-ring (as in FIG. 2B for example) or some other similar method such as threading. The protective cover 14 creates a tight fit against the rim of the port 16 such that fluid is prevented from flowing between the annulus and the interior of the completion string. The port 16 remains closed prior to rupture.

(70) Capping the port with a protective cover 14 serves several purposes. The cover 14 creates an air pocket of about atmospheric pressure between the outside of the burst disk and the inside of the cover 14. The space between the burst disk and the cover 14 is sealed and the space remains at or close to atmospheric pressure until the disk bursts. This facilitates bursting of the disk because it bursts against about atmospheric pressure and ensures that a predictable pressure will burst the disk. Furthermore, without the cover 14, the burst disks may not rupture simultaneously. If one burst disk were to rupture before the others, then fluid will flow out of that first ruptured port and the pressure will equalize between the inside and in the space exterior to the completion string, such as completion string 12 in which the burstable disk 20a is housed. The cover 14 prevents the pressure from rupturing the other disks from the outside in, which would cause fluid to flow into the tool. Preferably, as shown in FIG. 2B, the protective cover is fitted with an O-ring 32 to further ensure no leak path is present for fluids to pass.

(71) Referring to FIGS. 4A and 4B, in one embodiment of this invention, the burstable disk 20b is made from a single bore in the wall of the completion string 12. The port 16a for the burstable disk 20b is shown without a protective cover.

(72) Referring to FIGS. 5A and 5B, a burstable disk 20c can result from a plurality of concentric counterbores in the wall of a collar 40 or in the wall of the completion string 12. A port 16b for the burstable disk 20c is shown without a protective cover.

(73) Burst disks suitable for use in embodiments of this invention can also be of the conventional type used in prior art, for example, the burst disks supplied by Benoil™. If conventional burst disks are used, they can be built into or installed into a completion string and/or collars by conventional methods and used according to the methods described herein.

(74) Completion strings and collars having burstable disks according to the invention can be cemented or used in an open hole condition. The completion string 12 and collars 40 can be cemented to the wellbore 10 by filling the annular space 500 between completion string 12 and collars 40 and the wellbore 10. This is commonly known as the cemented condition. Using cement can substitute for the need for packers or other interval isolation devices. In embodiments, the amount of cement is minimized at locations of the burst disks 20 to ensure the cement is ruptured by the fluids flowing through the ruptured burst disks so as to ensure the treatment fluids reach the formation.

(75) When a completion string with burst disks is cemented into place, an interval of the completion string 12 that has the burst disks 20, can be covered by a shield (not shown) to prevent cement from sealing in the burst disks. A shield can also be used to cover burst disks in a collar if a collar of the type shown in FIG. 12 is used.

(76) The shield provides for a space to be maintained between the completion string and the wall of the wellbore to allow cement to flow continuously along the entire length of the completion string. The pressure exerted by the treatment fluid would be enough to fracture through the layer of cement that would have formed. Alternatively, in another embodiment, the completion string could be resting against the wellbore and, therefore, cement does not completely encircle the completion string allowing the burst disk ports to contact the wellbore. The pressure exerted by the treatment fluid would be enough to fracture directly into the formation.

(77) Referring to FIG. 12B, in another embodiment, the use of a shield can be avoided by using a collar where the central section of the collar includes fins 100 radially positioned around the circumference of the collar. The fins protrude outwardly from the wall of the burst disk collar thereby decreasing the space between the collar and the wellbore and centralize the completion string in the wellbore.

(78) To cement a completion string with a collar having fins in place, cement is pumped between the wellbore and the outside diameter of the completion string, through a void commonly known as the annulus. Fins 100 are arranged so that there are slots between them such that cement can pass by and continue to fill the annulus. Once the cement is cured, the subterranean hydrocarbon bearing formation, completion string, and collar(s) are rigidly connected to each other. In one embodiment of this invention, the projection of the fins 100 ensures that very little cement is between the fin 100 and the subterranean hydrocarbon bearing formation. The cement used for filling the annular space may have special properties to make it more suitable for the downhole environment and in one embodiment of this invention the cement may be acid soluble, unlike conventional cement used in oilfield operations. Each collar carries at least one burst port located within the fin 100.

(79) As a result, once cement fills the space between the completion string and wellbore, the portions of cement 500 adjacent the fins are thin enough such that treatment fluid can burst through the cement 500 when the burstable disks 148 rupture, as shown in FIGS. 10A to 10E.

(80) A person of ordinary skill in the art would understand that this technique of cementing the completion string to the wellbore, as taught by this invention, can be applied to treatment methods that use other conventional burst disks and sliding sleeves.

(81) The method of hydrocarbon bearing formation stimulation of one embodiment of this invention involves stimulating a hydrocarbon bearing formation by pumping treatment fluid under pressure through a treatment tubing and treatment tool. Prior to carrying out this method, the interval of the wellbore to be fractured must be isolated by conventional methods. The spacing between intervals would differ depending on the well, however typically, they may be spaced about every 30-50 meters. Hydraulic isolation in the exterior annulus can be achieved by having the completion string either cemented into position or by having external packers or other annular sealing device running along the longitudinal length of the completion string. Suitable annular sealing devices include cups and packers, and are well known in the art.

(82) Referring to FIGS. 1A to 1G, a method according to one embodiment of this invention involves first passing a completion string 12 down a wellbore 10, and then passing a bottom hole assembly 51 connected to treatment tubing 50, such as a coiled tubing or jointed pipe, inside the completion string 12. Bottom hole assembly 51, is further described with reference to FIGS. 11A-11D. The tool 51 carries radial passages along its circumference such that the interior of the treatment tubing 50 is in fluid communication with the exterior of the treatment tubing string 50. The tool 51 should then be positioned in a suitable location for treating the formation. The suitable location would be the position such that the pressure isolation devices (one of which is shown as 30), such as packers or packer cups, straddle one or more burst disk assemblies. In this position, treatment fluid that is pumped under pressure through the bore of the treatment tubing 50 and into a cavity defined between the isolation devices 30; causing a sufficient increase in pressure at the area of the burst disks so as to rupture the burst disks between the pressure isolation devices 30.

(83) In a cemented environment, once the burst disks rupture, the treatment fluid fractures the cement, and then can reach the formation to stimulate or fracture it. The treatment fluid can be pumped at a pressure between about 100 psi and about 20,000 psi to rupture the disks but other suitable pumping pressures are also possible. Preferably, pressure is applied at about 100 psi to about 10,000 psi. More preferably, pressure is applied at about 3,000 psi to about 4,500 psi. In this invention, stimulation can begin anywhere along the completion string where burst disks are located and there need not be any pre-defined order of treatment. For example, stimulation can occur at the distal end of the completion string first and then moved up hole, or in the reverse order, or stimulation can start partway down the wellbore and then proceed either up or downhole. This also allows some of the burst disks to be opened in one treatment and others to be left for treatment at a later date.

(84) Therefore, following treatment, the treatment tubing, and hence the tool, can be moved up or down hole to straddle another set of burst disks. Each set of burst disks placed in the treatment tubing can be treated independently as successive treatments are isolated from each other. As such, each isolated interval of formation can also be treated separately.

(85) Since the interval is isolated, pressure builds within the completion string very quickly. Furthermore, the same pressure can be applied for each treatment. The operation is further simplified because, unlike methods of prior art, each burst disk can be identical and having the same pressure threshold.

(86) Referring to FIGS. 6A to 6G, in another embodiment of this invention, the formation is stimulated by pumping treatment fluid under pressure in an annulus 56 between the treatment tubing 50 and completion string 12, rather than through the treatment tubing 50 and the treatment tool 51. The cross sectional area of the annulus 56 is greater than the cross sectional area of the treatment string 50, so higher pumping rates can be achieved, which is vital for some operations.

(87) The treatment tool 51 with isolation devices 30 can be used to isolate an interval within the completion string. Further, the wall of the completion string 12 similarly has collars 40 which carry burst ports 20 arranged therein as described in above described embodiments. The treatment tool 51 is first positioned such that the isolation devices 30 straddle a set of burst disks. As more particularly shown in FIG. 6A, treatment fluid or any useful fluid is then pumped into the treatment string 5) and ejects out of the opening 24 of the treatment tool 51 to rupture the burst disks in the ports 20. However, in this alternative embodiment shown in FIG. 6G, once a set of burst disks are ruptured, the treatment tool 51 and isolation devices 30 are moved downhole from the set of ruptured disks. Treatment fluid is then pumped downhole under pressure in the annulus 56 between the treatment tubing 50 and completion string 12, rather than through the treatment tool 51. Once the treatment fluid reaches the ruptured burst disks in the ports 20, it will exit the completion string 12 and stimulate the adjacent formation. The treatment tool 51 and therefore, the isolation devices 30, are situated downhole from the set of burst ports 20 to prevent the treatment fluid from fracturing any area downhole of the set of burst ports 20. The steps of this method can be repeated after moving the treatment tool uphole to the next set of burst disks to be ruptured by the treatment tool.

(88) Referring to FIGS. 7A and 7B, in another embodiment of this invention, isolation devices are not needed; treatment fluid is pumped down the completion string from surface and all the burst ports can be subject to the treatment fluid pressure simultaneously, and will also rupture simultaneously. As indicated by arrows 60, the treatment fluid will then flow into the hydrocarbon bearing formation 14 from the ports 20 at the same time.

(89) Referring to FIGS. 8A to 9E, in another embodiment of this invention, burst disks mounted in collars (20) with different burst pressure thresholds can be set such that a series of burst disks rupture in a staggered manner according to various fluid pressures being applied. FIG. 8A shows the completion string 12 inserted in the wellbore and ready for stimulation operations. Burst pressures at each burst disk can increase uphole with the burst disk at the toe of the wellbore set with the lowest burst pressure. Treatment fluid is then pumped down the completion string to rupture the burst disk and continuously pumped to stimulate the first interval located at the toe of the wellbore, as shown in FIG. 8B. Once the first interval is stimulated, it is isolated from fluid communication with the remainder of the completion string 12. This isolation can be achieved by setting a sealing device 80 between the burst disks in the first interval and the next interval to be stimulated, as shown in FIG. 8C. The next interval can then be stimulated, as shown in FIG. 8D. The sealing device 80 can be a packer or other device known in the art. Another way to isolate the interval is by pumping frac balls 90 or particulate material down the completion string, which block the passageway though the ruptured burst disks, as shown in FIG. 9A. The next interval would be situated uphole from the first zone. The steps are then repeated for stimulating the next interval and subsequent interval, as shown in FIG. 8E. The sequence need not start at the distal end of the completion string, the burst disks can be ruptured in any order. During wellbore completion operations, it is sometimes necessary it insert an array of different tools in the wellbore to perform different functions. The most cost effective way to insert these tools in a wellbore is typically on a wireline for easy insertion and removal of the tool. In order to insert wireline borne tools in a horizontal wellbore, the ports in the toe of the wellbore are ruptured, as shown in FIG. 8B. This provides communication with the formation and allows wireline tools to be pumped down the wellbore, which would be impossible if the distal end of the wellbore was sealed.

(90) The method described with reference to FIGS. 8A to 9C can be practiced if the wellbore is cemented with only a completion string present and to pump treatment fluid through the completion string; with a treatment string present and to pump treatment fluid through the treatment string; or to pump through the annulus between the completion string and the treatment string, as described in the embodiments above.

(91) Another embodiment of this invention involves the use of burst disks, as disclosed in this application, in enhanced oil recovery, for example SAGD or VAPEX. Typically, there would be a pair of horizontal injection and producing wells. Burst disks located in the walls of a completion string fed down the injection well would rupture under the pressure of steam or solvent being pumped into the injection well. The steam or solvent liquefies the oil situated between the pair of horizontal wells. Burst disks located in the walls of a completion string fed down the producing well would then be ruptured under pressure, allowing the liquefied oil to migrate into the producing well through the ruptured burst disks and later collected from the producing well.

(92) In an alternative embodiment, the completion string is inserted into the wellbore and cemented to the hydrocarbon bearing formation. In place of periodically spaced collars carrying burst disks the completions string can be locally provided with communication with the cement. Examples include but are not limited to, conventional burst disks, sliding sleeves and/or any method of opening a port in the completion string wall; having the completion string wall reduced in thickness or even completely to partially removed by any means to create a region of low to zero strength in the completion string wall. The wall material of the completion string can be removed by cutting, machining, abrading, chemical removal, or other means. The resultant region of low to zero strength will allow fracturing through the cement thus behaving—similarly to a burst disk and allow the treatment fluid to stimulate the subterranean hydrocarbon bearing formation when the treatment fluid is pressurized in accordance with any of the methods described above. Alternatively, the cement can be acid soluble, and in place of high pressure the stimulation is initiated by an acid spearhead. Some pressure would be needed to either rupture the burst disks or penetrate a region of low strength of the completion string wall, but the pressure is much lower than would be used in a pressure initiated stimulation treatment.

(93) All of the above embodiments are generally described in terms of the completion string being cemented to the hydrocarbon bearing formation. It is possible to use the above described invention in an open hole, however isolation devices must be used between the outside of the completion string and the hydrocarbon bearing formation to hydraulically isolate the area to be stimulated, such that the treatment fluid will flow from the bore of the string that contains treatment fluid, through the ruptured burst ports, and into the formation. If the exterior annular isolation devices were not present the treatment fluid may not flow where desired.

(94) Referring to FIGS. 11A to 11D, a bottom hole assembly (BHA) 51 is used on the distal end of the treatment string such as treatment string 50. When inserting the BHA 51 into a wellbore, the wellbore is normally filled with a service fluid (often this is water). To insert the tool 51 on a treatment string in to a wellbore the service fluid must be displaced. Service fluid flows through ports 101, through central passage 102, past seat 104 and out ports 106. It reenters the BHA 51 through ports 108 and continues out the BHA through central passage 110 and up the bore of the treatment tubing.

(95) When BHA 51 is being removed from the wellbore 10 the treatment string 50 is full of service or treating fluid, and the fluid must escape from the interior of the treatment string at a controlled rate. If the flowrate or pressure differential of the fluid exceeds a predetermined threshold, then the isolation elements 30 will set, causing the tool to seal against the interior of the completion string 12 wall, preventing removal of the tool. This is a desirable attribute when preparing for a stimulation operation and the isolation elements need to be set to achieve hydraulic isolation against the completion string 12, but not when attempting to remove the treatment string 50 and the BHA 51 from the wellbore 10. To remove the treatment tool 51, the treatment string 50 is removed from the wellbore 10 at a controlled rate, such that the differential pressure across piston 112 does not cause it to move and seal against seat 104. Sealing element 30 is shown in FIGS. 11A and 11C with the largest diameter portion facing left, there is a matching sealing element (not shown) attached to the left side of the BHA 51 that has the largest diameter portion facing right. In the area defined between the two sealing elements 30 are the ports 108 and piston 112.

(96) Referring to FIG. 11D, in the piston area, as the fluid pumping rate is increased, differential pressure builds on the left face 116 of the piston 112 in the orientation shown, and is resisted by spring 114. As the pressure continues to build on the face 116, the spring is compressed as the piston 112 moves to the right. At a predetermined differential pressure, the right piston face 118 will contact the seat 104 and produce a fluid seal such that fluid flow from ports 106 to central passage 102 is prevented.

(97) In a stimulation operation, as the pumping rate of treatment fluid increases the fluid moves out through ports 108 as the piston 112 has sealingly engaged seat 104 to prevent the fluid from flowing through the BHA. Instead, the fluid moves through ports 108 and forces the lips of the sealing elements 30 against the completion string 12 wall, creating a pressure tight seal. Port 108 is located between two isolation elements 30 which straddle a collar or other portion of the completion string 12 that has been partially or completely removed such that it is suitable for a formation stimulation operation, as described hereinabove. Once the treatment fluid has reached the critical pressure, it will then rupture the burst disks and stimulate the hydrocarbon bearing formation 3 according to the methods described hereinabove. The sealing portions of the valve are comprised of ceramic material (silicon nitride for the piston end and boron carbide for the seat).

(98) As disclosed in priority application CA 2,683,432, paragraph [0072], the treatment tool may include an equalization valve, shown in FIGS. 11A to 11D. The purpose of this equalization valve is to allow the pressure of the treatment fluid in the treatment tubing to be equalized with the pressure in the annulus, formed by the treatment tubing and the completion string, below the bottom isolation device. Once the pressure above and below the bottom isolation device is equalized, the treatment tool can be moved without being damaged. One way this equalization valve would work is that the valve is in the open position while inserting and moving the treatment tubing. Then as the treatment fluid flow rate down the treatment tubing is increased, the equalization valve begins to shift. Once the treatment fluid exceeds a preset rate, the valve will close and all of the flow will be contained between the isolation devices on the treatment tool. Once the flow drops off, the valve will then reopen and the pressure above and below the bottom isolation device will equalize. It is important to note that this equalization valve is not operated by differential pressure above and below the lower packer cup and is not merely a check valve.

(99) As disclosed in priority application CA 2,683,432 (FIGS. 11A, 11B and 11C), the BHA 51 or treatment tool accesses the annulus, formed by the treatment tubing and the completion string 12 below the bottom isolation device 30, through flow ports 101.

(100) As disclosed in priority application CA 2,683,432 (FIG. 11D), the right piston face 118 of the piston 112 comprises a hardened needle which will contact hardened valve seat 104. Service fluid can flows out four flow ports 101 as shown, each being 0.5″ in diameter. The right piston face 118 can move 0.25″ to close on the hardened valve seat 104. The piston 112 can be fit with low drag, high pressure rod packing (Hallite 621). The piston 112 is biased using a 15-20 lb/in preloaded compression spring 114. The compression spring 114 is located between a stop 115 on the valve body and a shoulder 117 on the piston 112. The left face 116 of the piston 112 receives the treatment fluid flow rate from the central passage 110.

(101) As disclosed in priority application CA 2,683,432 (FIG. 11A), the bottom isolation device 30 can be a 4.5″ polyurethane or rubber packer cup.

(102) Referring to FIG. 14, in another embodiment of this invention, the bottom hole assembly is not used. In this embodiment the completion string 12 is inserted in the well bore, and may either be cemented or left open hole. In the case of open hole, exterior annulus isolation elements are required to isolate the interval of interest. In the cemented case, cement 26 secures the completion string 12 to the hydrocarbon bearing subterranean formation 3. The treatment string 50 is inserted into the wellbore and carries a isolation element 30 on its distal end. Particulate matter 602, such as sand, is deposited in the completion string to isolate burst ports by creating what is known as a sand plug. 20. The treatment string 50 is then positioned such that the burst port or ports of interest are isolated between the treatment string and its isolation element 30 and the particulate matter (60). Treatment fluid is then pumped down the treatment string 50, ruptures the burst ports 20 and stimulates the interval of interest. Following stimulation, the sand plug can be removed and replaced at a different interval of interest and a further stimulation operation performed. In another embodiment of the present invention, a mechanical bridge plug is used instead of a sand plug. The treatment string 50 is then positioned such that the burst port or ports of interest are isolated between the treatment string and its isolation element 30 and a sealing device (not shown) or the particulate matter

(103) Referring to FIGS. 13A and 13B, in another embodiment of this invention, a treatment string 50 inserted into the completion string 12 and run down the wellbore. FIG. 1C shows a partial cutout of the completion string 12 to reveal a tool 51 in fluid communication with the treatment string 50. The treatment string 50 may be coiled tubing or jointed pipe. The tool can be any conventional tool for use in these types of operations and that can be attached to a treatment tubing and straddled by at least two isolation devices. These isolation devices may be packers or cups or other sealing means. At least one section of the tool 51, which is a type of cup-cup tool, has an opening 24 out of which fluid can be ejected into the space within the completion string 12. This section of the tool is straddled by isolation devices 30 such that any fluid that ejects from the opening 28 would remain confined in the space between the isolation devices 30.

(104) In each interval, there is an area of the completion string 12 where the wall of the completion string or collar is thinned 20. The thinned areas of the completion string or collar are where the ports 16 will open following rupturing of the burst disks.

(105) The fluid that ejects from the opening 28 of the tool 51 causes an increase in pressure that is sufficient enough to rupture the burst disks, as shown in FIG. 1D, and then stimulate the formation, as shown in FIG. 1E. Following stimulation of the isolated area, the tool may be re-positioned at the next desirable location to be stimulated, as shown in FIG. 1F. The tool may be moved uphole or downhole from the initial ruptured burst disks.

(106) Another embodiment of this invention uses the treatment tool combined with the equalization valve in horizontal or vertical wellbores to straddle and isolate intervals containing perforations, holes cut by abrasive jetting, sliding sleeves, or burst disk ports for the purpose of performing treatments. Referring to FIG. 15, a sliding sleeve 206 according to an embodiment of this invention can be adapted to open and close a port 200 in the wall 202 of a tubular member having a burstable disk 204 in the port 200. The sleeve 206 can be slide in the direction 208 whereby the port 200 is opened when the aperture 210 is in at least partial registration with the port 200. The sleeve can be actuated by convention means.

(107) In one embodiment, the method of one embodiment of this invention involves stimulating a formation by pumping treatment fluid under pressure through a treatment tubing and treatment tool. Prior to carrying out this method, the interval of the wellbore to be fractured must be isolated by conventional methods. The spacing between intervals would differ depending on the well, however typically, they may be spaced about every 100 meters. Hydraulic isolation in the exterior annulus can be achieved by having the completion string either cemented into position or by having external packers or other annular sealing device running along the longitudinal length of the completion string. The cement, external packers and annular sealing devices provide hydraulic isolation along the annulus formed by the completion string and the open hole of the wellbore.

(108) A person skilled in the art would understand that treatment fluid needs to be pumped at a sufficient pressure to rupture the burst disks and that this pressure varies depending on the type of burst disk and location of the burst disk. Preferably, the pressure at which fluid is pumped is less than the anticipated break pressure. As discussed above, the initial pumping pressure may in one example be at about 4,200 psi or 31 MPa and at 9000 psi at surface (11,000 psi downhole) in another example.