Method and apparatus for single-trip wellbore treatment

Abstract

The apparatus consists of a tubular housing carried into the well on a workstring. A series of spaced isolation modules is provided for each zone and carried into the well on a tubular conduit. The first, or most downstream module includes first and second sealing mechanisms to isolate the first zone to be treated. A full bore valve is provided that is activated to closed position by an activating component in response to a source of a first level of pressure to isolate the first zone from other parts of the well bore. A port within the housing is initially blocked but selectively opened concurrently with the activation of the first sealing means to manipulate the second sealing mechanism to fully isolate the selected zone and the module. As the module is activated, a second full bore valve is activated to seal the interior of the housing upstream of the first module by manipulation of the tubular string.

Description

CROSS-REFERENCE TO RELATED APPLICATION AND CLAIM OF PRIORITY

This is a utility application claiming priority from U.S. provisional patent application No. 61/305,621, filed Feb. 18, 2010, entitled “Method and Apparatus For Single-Trip Wellbore Treatment”, Gregg W. Stout, inventor.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to apparatus and methods for oil and gas wells to enhance the production of subterranean wells, either open hole or cased hole, and more particularly to improved multizone stimulation systems.

2. Brief Description of the Prior Art

Wells are drilled to a depth in order to intersect a series of formations or zones in order to produce hydrocarbons from beneath the earth. The drilled wells are cased and cemented to a planned depth and then may cased and cemented or a portion left open hole. Producing formations intersected with the well bore in order to create a flow path to the surface. Stimulation processes, such as fracing or acidizing or other chemicals or proppants, are used to increase the flow of hydrocarbons through the formations. The formations may have reduced permeability due to mud and drilling damage or other formation characteristics. In order to increase the flow of hydrocarbons through the formations, it is desirable to treat the formations to increase flow area and permeability. This is done most effectively by setting either open-hole packers or cased-hole packers at intervals along the length of the wellbore. These packers isolate sections of the formations so that each section can be better treated for productivity. Between the packers is a frac port and in some cases a sliding sleeve or a gravel pack screen with sliding sleeves. In order to direct a treatment fluid through a frac port and into the formation, a seat may be placed either on top of a sliding sleeve or below a frac port. A ball or plug may be dropped to land on the seat in order to direct fluid through the frac port and into the formation.

One method places a series of ball seats below the frac ports with each seat size accepting a different ball size. Smaller diameter seats are at the bottom of the completion and the seat size increases for each zone as you go up the well. For each seat size there is a ball size so the smallest ball is dropped first to clear all the larger seats until it reaches the appropriate seat. In cases where many zones are being treated, maybe as many as 20 zones, the seat diameters have to be very close. The balls that are dropped have less surface area to land on as the number of zones increase. With less seat surface to land on, the amount of pressure you can put on the ball, especially at elevated temperature, becomes less and less. This means you can't get adequate pressure to frac the zone or the ball is so weak, the ball blows through the seat. Furthermore, the small ball seats reduce the I.D. of the production flow path which creates numerous other problems. The small I.D. prevents re-entry of other downhole devices, i.e., plugs, running and pulling tools, shifting tools for sliding sleeves, perforating gun size (smaller guns, less penetration), and of course production rates. In order to remove the seats, a milling run is needed to mill out all the seats and any balls that remain in the well.

The size of the ball seats and related balls limits the number of zones that can be treated in a single trip. It would be advantageous to replace the use of the ball seats with a workstring actuated isolation device, such as a flapper or rotating ball, to allow the treatment of an unlimited number of zones in a single trip.

Another method is that disclosed in U.S. Pat. No. 7,543,634 B2. This method places sleeves in the I.D. of the tubing string. These sleeves cover the frac ports and packers are placed above and below the frac ports. Varying sizes of balls or plugs are dropped on top of the sleeves and when pressing down the tubing, the pressure acts on the ball and the ball forces the sleeve downward. Once again you have the restriction of the ball seats and theoretically, and most likely in practice, when the ball shifts the sleeve downward, the frac port opens and allows the force due to pressure diminish off before the sleeve is fully opened. If the ball and sleeve remain in the flow path, the flow path is restricted for the frac operation.

It would be advantageous to have a system that had no ball seats that restrict the I.D. of the tubing and to eliminate the need to spend the time and expense of milling out the ball seats, not to mention the debris created by the milling operation. Also it would be beneficial to have a system that fully opens the sliding sleeve before sleeve activating pressure bleeds down, to assure the sleeve is fully opened before treating the formation.

Furthermore, it would be greatly advantageous to eliminate the time and logistics required for dropping numerous balls into the well, one at a time, for each zone in the well to be treated.

In some well completions the operator may want to perforate below the packer. If the completion has small I.D. ball seats, the maximum O.D. of the perforating guns must drift through the ball seats. Small I.D. ball seats mean small O.D. perforating guns. It is well known in the industry that the smaller the O.D. of the perforating gun, the less the penetrating performance of the gun. It would be very advantageous to be able to run the largest O.D. gun possible inside of the tubing to achieve the greatest penetration through the tubing and casing walls to get the deepest penetration into the formation.

Some zones in the formation are very close together or water is nearby. Fracturing programs sometimes want to limit the length of the zone to be treated so isolation packers with sliding sleeves need to be set very close together. To achieve this it would be beneficial to have a short compact packer-sliding sleeve assembly where several assemblies could be stacked closely together. One of the advantages of the present invention is to integrate to components of the packer and sliding sleeve to produce a reduced overall length apparatus to address the completion of closely positioned zones.

SUMMARY OF THE INVENTION

A single trip multizone well treating method and apparatus provides a means to progressively stimulate individual zones through a cased or open hole well bore. The need to drop and mill balls and seats for each zone or run hydraulic control lines from the surface to actuate a series of isolation devices has been eliminated. Also, the I.D. restriction created by balls and seats has been eliminated to provide a full bore completion. The full bore completion allows use of larger perforating guns when thru-tubing perforating is desired. A unique feature of this system is that the operator can progressively treat each zone up the hole by moving the workstring up and down a short distance to release a flapper valve selectively for each zone. Applied pressure to the flapper both opens a sliding sleeve and sets a packer and then shifts the flapper below the frac port so a pumping treatment can commence. The apparatus is presented as a “Frac Module” that consists of three major components, a packer, a sliding sleeve, and a workstring actuated fluid isolation device which are integrated together in an assembly that would be shorter in length for closely placed zones. One Frac Module is used per zone and the frac module is stacked with tubing spacers through all zones that need treatment and zonal isolation.

Stated a slightly different way, the invention provides a full bore, single trip multizone subterranean well treating apparatus. The apparatus is carried into the well on a tubular workstring, which may also be later used as the production tubing. A tubular housing is defined on the workstring and includes a central first fluid passageway therethrough. A plurality of treatment modules are provided on the housing, each module being pre-determinedly spaced on the housing for operable alignment with a zone in the well. Each module includes a tubular housing member with a treatment fluid port therein and a control chamber selectively communicable with the port. First and second spaced sealing mechanisms, such as packers, are provided to isolate the selected zone from other portions of the well. A first full bore valving mechanism is initially positioned in the housing in open position and is selectively activatable to closed position to block fluid under pressure from being transmitted within the tubular housing and across the valving member. Activation means are provided for the first valving means and responsive to a first level of pressure applied through the workstring to open the port and place a chamber in fluid communication with a fluid passageway within the housing. Pressure within the housing member above the first level further activates the a first sealing means, or packer, to set position. A second fluid flow passageway in the housing includes a blocked port opening to the interior of the housing, and the port is opened during activation of the first sealing means, or packer. A second activation means, such as a sleeve, is responsive to a pressure level in said tubing in excess of that required to set the second sealing means and to open a treatment port. In each of the modules upstream of the module used to isolate the first zone to be treated, there is provided a full bore valve in initial open position but shiftable to closed position by mechanical manipulation of the workstring to block fluid flow across the valve.

This invention provides an improved multizone stimulation system to improve the conductivity of the well formations with reduced rig time and no milling. The equipment for all zones can be conveyed in single workstring trip and frac units can stay on location one time to treat all zones.

In a preferred embodiment, work string weight is set down and pressure is applied to the lowermost isolation device, such as a flapper. The flapper is released and allowed to close. The flapper is mounted on a sleeve that is shear pinned. A low initial pressure shifts the flapper and sleeve downward to open a pressure port. Tubing pressure enters the port to shift the sliding sleeve downward to an open position to uncover the frac port and simultaneously begin setting a packer located immediately above the frac port. The setting motion within the packer opens a port to the tubing to allow tubing pressure to travel up a control line to the next upper zone to activate a flapper release mechanism, but the next upper flapper does not close at this point. Tubing pressure is increased to fully set the packer and the flapper/sleeve shears and shifts downward to a position below the frac port. In this position, the flapper/sleeve then rests on top of the sliding sleeve. With the frac port now fully open, the first zone is treated while the workstring remains in the set-down position. After the stimulation of the lower zone, the work string is picked up a short distance to release the flapper only in the next upper zone so the next upper zone can be treated. All upper zones are then progressively treated using the same process. A set-down and pickup type packer can be used above all of the frac Modules and above the uppermost set of perforations, assuming all zones were perforated initially. A production packer can be run in the string above the set-down packer, if desired, and be set after all zones are completed. Once the well is nippled-up the well can be put on production. If flapper valves are used, they will open and allow flow. It is also possible to make a trip into the well and break the frangible flapper discs. If sliding sleeves are used, shifting tools can be run in to open or close the sliding sleeves.

BRIEF DESCRIPTION OF THE DRAWINGS

FIGS. 1a, 1b, and 1c placed end-to-end make up a schematic view of the present invention.

FIG. 2 is a schematic view of three Frac Modules assembled in tandem in a well completion.

FIG. 3 is a schematic view of three cased and perforated zones isolated with a completion string of tools.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

With reference to FIG. 1a, a schematic of the present invention shows a 90 degree lengthwise cross-section of the apparatus. This portion of the apparatus is the packer with only a packing element. A packer may be used that has a slip system added and a packer may be used that has a release devise added. Top sub 1 has a connecting thread at the top end 2, an internal thread 3, and o-ring seals 4 and 5. Shear Screws 6 shearably connect Top Sub 1 to Shear Ring 7. Shear Screws 8 shearably connect the Top Sub 1 to Push Sleeve 12. The hole 9 communicates with hole 13. A fitting 10 seals in hole 9 and also connects to hydraulic control line 11. Hole 13 is located inside of Flow Body 14. Seals 15, 16, 4, 5 seal between the Top Sub 1 and the Flow Body 14 to isolate flow paths 9 and 13 from pressure inside the tool 22 or outside the tool 23. Port 20 has Seals 17 and 18 to seal off Port 20 with Push Sleeve 12. Seals 18 and 19 with Push Sleeve 12 seal off port 21 to prevent pressure in tool 22 from entering port 20. Seals 24 and 25 in Flow Body 14, seal with Packer Mandrel 26.

Thread 27 attaches Flow Mandrel 14 to Packer Body 26. Packing Element 28 rests on the Packer Mandrel 26 and between faces 30 and 31. Gage Ring 29 is attached to Piston 32 with thread 37. Piston 32 slides between Piston Housing 38 and Mandrel 26 and seals 33 and 34 act as piston seals. Body Lock Ring 35 threadably engages Piston Housing threads 44 so items 35 and 44 move together. Body Lock Ring 35 sets on smooth S surface 45 and at a later point in time engages Piston threads 46. Screw 36 prevents rotation of Body Lock Ring 35 relative to Piston 32. Connector 43 is attached to Mandrel 26 with thread 39 and seals 41 and 42 create a seal between items 25 and 43. Hole 40 in Connector 43 communicates with Piston 32.

With reference to FIG. 1b, Connector 43 and hole 40 continue in the apparatus. Lower Pickup Sleeve 49 is attached to Connector 43 with thread 53 and seals 47 and 48 seal between the items 43 and 49. Hole 40 communicates with chamber 54. Release Sleeve 55 slides within Connector 43 and seal surface 52 seals at O-rings 50 and 51. Upper Pickup Sleeve 56 slides inside of Lower Pickup Sleeve 49. Surfaces 57 and 58 engage during pickup while surfaces at location 70 make contact during set-down.

Dynamic Seals 59, 60, and Static Seals 61, and 62 seal on seal surface 63 of the Upper Pickup Sleeve 56. Upper Pickup Sleeve 56 is connected to Housing 65 with threads 64.

Housing 65 attaches to Frac Port Housing 66 with thread connection 67 and seals 68 and 69 seal between items 65 and 66. Seals 72 and 73 are positioned on Release Sleeve 55 and form a seal on Frac Port Housing 66 at seal surface 71. Shear Ring 74 is shearably connected to Release Sleeve 55 with shear screws 75. Shear Ring 74 is trapped in pocket 76 so Release Sleeve 55 can't move up or down. Shifting Profile 77 inside of Release Sleeve 55 engages a shifting tool (not shown) so that the shifting tool can engage the profile 77 and move the Release Sleeve 55 upward.

The bottom of Release Sleeve 55 has a finger 78 attached. The finger 78 engages the Flapper 79 at location 84. The Flapper 79 is affixed to Flapper Seat Sleeve 81 with axle 80 so the Flapper 79 is free to pivot around axle 80. Flapper Seat Sleeve 81 is attached to Seat Housing 83 with shear pin 82. Flapper Seat Sleeve 81 can slide downward into Seat Housing 83 until faces 84 and 85 come into contact. Seat Housing 83 is shear pinned to Frac Port Housing 66 with Shear Pins 86. Seals 87, 88, 89, and 90 are positioned in Barrel 91 and prevent pressure from moving from location 22 to location 23 or vice-versa.

One or more Frac Ports 92 are located in Frac Port Housing 66. The ports 92 go completely through the wall of the Frac Port Housing 66. The Frac Port Housing has gun drilled hole 93 and 94 that do not intersect the Frac Ports 92 or Shear Screw hole 86. Gun drilled hole 93 and 94 are isolated from each other by plug 95 and seals 96, 97, 98, 99, and 102. Port 100 communicates with gun drilled hole 93 and Port 101 communicates with gun drilled hole 94, or vice-versa.

Gun Drilled Hole 93 communicates with chamber 103 and acts on seals 104 and 105 located inside of Housing 65 and Release Sleeve 55. Seals 104 and 105 are located on the I.D. and O.D. for Shift Piston 106. Therefore, pressure in gun drilled hole 93 acts on Shift Piston 106 and is isolated from pressures 22 and 23.

Shift Piston 106 is shearably attached to Upper Pickup Sleeve 56 with shear pin 111. Expanding Lock Dogs 107 and 109 are located in retaining slots on Shift Piston 106. Lock Dog 107 is designed to engage in groove 108 inside of Lower Pickup Sleeve 49 and Lock Dog 109 is designed to engage in groove 110 on the O.D. of Release Sleeve 55. Locking Keys 112 fit into slots 115 that are located in Upper Pickup Sleeve 56. The Locking Keys 112 have teeth that expand into the I.D. thread profile 114 of Lower Pickup Sleeve 49. Extended portion 113 of Shift Piston 106 slides under Locking Keys 112 in order to expand and engage the teeth into profile 114 thus locking the Lower Pickup Sleeve 49 to the Upper Pickup Sleeve 56 during the run-in configuration.

With reference to FIG. 1c, note the continuation of gun drilled holes 93 and 94 in Frac Port housing 66. In this figure, Gun Drilled Hole 93 communicates with control line 116 which attaches control line 117 which communicates with Shift Piston 106. Control Line 117 becomes the same control line as Control Line 11 in FIG. 1a so that Frac Modules in a lower zone can act on Shift Piston 106.

Gun Drilled Hole 94 communicates with chamber 118 and chamber 118 is adjacent to Sliding Sleeve Piston 121. The Sliding Sleeve Piston 121 is positioned between Frac Port Housing 66 and Sliding Sleeve 124 and seals between the two with seals 119 and 120. The Sliding Sleeve Piston 121 is shearably attached to Sliding Sleeve 124 with Shear Screws 122. The Sliding Sleeve Piston 121 houses a Lock Ring 123 which engages shoulder 127. Chamber 128 is below the Sliding Sleeve Piston 121 and communicates with ports 129 which communicate with pressure 23. In summary, port 101 communicates with chamber 118 to communicate with Sliding Sleeve Piston 121 and the lower side of the Piston communicates with pressure 23.

Frac Port Housing 66 is connected to Sleeve Housing 130 with thread 131. Bottom Sub 135 is connected to Sleeve Housing 130 with thread 132 and seals 133 and 134 create a seal between the two. The Bottom Sub 135 has pin thread 136 facing down.

Sliding Sleeve 124 always isolates chamber 128 from pressure 22 with upper and lower seals 125 and 126. The Sliding Sleeve 124 has collets 138 and 139 machined into the sleeve. These collets either engage in recess 144 or recess 143 to hold the Sliding Sleeve 124 in either the open or closed position. Anti-rotation Keys 137 slide in slot 130 and set in slots 145 located in the Sliding Sleeve 124. Key 137 shoulder 141 engages Bottom Sub 135 shoulder 142 to limit downward movement of Sliding Sleeve 124 so that Collets 138 and 139 are not loaded in compression. Collets 138 and 139 engage a shifting tool, not shown, used to either shift the Sliding Sleeve 124 open or closed.

With reference to FIG. 2, Frac Module 146 is comprised of the apparatus described in the combination of FIGS. 1a, 1b, and 1c. This illustration shows three Frac Modules 146a, 146b, and 146c placed around producing zones 147 and 148 and inside casing 149 with the casing surrounded by cement 150. Perforations 151 and 152 are in communication with the Frac Port Windows 92 shown in FIG. 1b. Packing Elements 153 seal on the I.D. of casing 149 in order to isolate zones 147 and 148 from each other. Obviously, this can be done on many zones located in the well bore. Control lines 117 allow pressure communication from Frac Module 146c to Frac Module 146b and then from Frac Module 146b to Frac Module 146a and so on for every zone to be treated.

Description of Preferred Operation

With reference to the example in FIG. 3, a typical completion is shown but many variations of this occur as know by those who are familiar with the variations that occur in configuring well completions.

A well has been drilled, cased, cemented, and perforated, although this system may be used in open hole completions with selection of the appropriate packers. Casing 149 is shown in this example with perforations 151, 152, and 154 in the casing. A sump packer 155 is properly located and set below the lowermost zone 154.

A “completion string” is run into the well consisting of a Locator Snap Latch Seal Assembly 156, Tubing Spacer 160, Frac Module 146c, Tubing Spacer 159, Frac Module 146b, Tubing Spacer 159, Frac Module 146a, Tubing Spacer 161, Service/Production Packer 157, and releasable work string 158 where a production string can be run to replace to workstring at a later date in the completion. The length of Tubing Spacers 159 and 160 are made to position the Frac Modules 146 between the producing zones 162, 163, and 164. The Service/Production Packer 158 can be of the straight pick-up and set-down style where no rotation is required to move the packer up the hole and re-seal.

The single trip completion string is landed in sump packer 155. The location of Sump Packer 155 was based on logs of the zones so that all equipment could be spaced out properly. Therefore, by locating the completion assembly on the Sump Packer 155, all Frac Modules 146 will be properly positioned in the well. Snap Latch Seal Assembly 156 can be used to verify position of the system before setting any of the above packers. The Locator Snap Latch Seal Assembly 156 seal in the sump packer 155 and will locate on the bottom of the Sump Packer, although “top of the packer” snap latch seal assemblies can be used as well. The Locator Snap Latch Seal Assembly 156 is designed to allow pulling of the Work String 158 to get a load indication on the Sump Packer 155 and then snap back in and put set-down weight on the Sump Packer 155. The load required to snap out is recorded so an operator can know how much to pull with the workstring before snapping out. Collets on the Locator Snap Latch Seal Assembly 156 can be designed to snap at specified loads. The above steps are common in the art of completing wells.

To explain operation of the Frac Modules, this discussion will begin with stimulation of the lower-most zone 164. The lowermost Frac Module 146c is assembled slightly different from all the above frac Modules 146b, 146a, and 146z, z being any number of zones. In Frac Module 146c, referring to FIG. 1b, the Flapper 79 will be installed in the released position, i.e., finger 78 will be disengaged from location 84, so the Flapper 78 is free to go to the closed position against Flapper Seat Sleeve 81 and also be free to allow fluid from below the Flapper 79 to open the Flapper 79 to allow the work string 158 to fill with well fluid during tripping into the well and stinging into Sump Packer 155 with Locator Snap Latch Seal Assembly 156. Also control line hole 93 is plugged at fitting 116.

Reference Point to Repeat Process

After set-down weight is placed on the sump packer 155, maybe 10,000 to 20,000 pounds, the Service Packer 157 will be set with set-down weight, and the Hydrils can be closed on the workstring 158. Frac lines can be attached at the surface and pressure can be applied down the workstring 158 against the Flapper 79 in Frac Module 146c.

Referring to FIG. 1a, 1b, and 1c it will be explained 1) how the packing element 28, or a packing element plus a slip system (not shown), is actuated, and 2) how the Sliding Sleeve 124 is opened, and 3) how the Flapper/Seat Assembly, items 79,80,81,83, moves downward below the Frac Port 92 and lands on top of the Sliding Sleeve 124, and 4) how the Lower Pickup Sleeve 49 is unlocked, and 5) how the Flapper 79 in Frac Module 146b, in the next upper zone 163, is put into the prepare for release mode.

In operation, the workstring 158 pressure 22 acts on the closed Flapper 79 in Frac Module 146c. Shear pin 82 is set at a lower shear value than shear screw 86 so pressure 22 acts on seal 98 and Flapper 79 and Flapper Seat Sleeve 81 causing Shear Pin 82 to shear. Face 82 moves downward to contact face 85 so that the Flapper Seat Sleeve 81 shifts below ports 100 and 101. Pressure 22 travels thru port 101 and into Gun Drilled Hole 94 to act on Sliding Sleeve Piston 121. Hole 94 is plugged with plug 95 so pressure only acts on piston 121. The piston 121 leads shear screw 122 which loads Sliding Sleeve 124 and shifts the Sliding Sleeve 124 downward to the full open position where the shoulder 141 of Key 137 contacts Bottom Sub shoulder 142. Frac Port 79 is now open and pressures 22 and 23 communicate.

Pressure 22 also travels through port 100 and up Gun Drilled Hole 93 to act on seals 104 and 105 of Shift Piston 106 to shear pins 111 and move Shift Piston 106 upward. Upward movement of Shift Piston 106 releases Locking Keys 112 so that Lower Pickup Sleeve 49 and Upper Pickup Sleeve 56 are free to move until surfaces'57 and 58 make contact. Although, surfaces 57 and 58 will not make contact at this time because the operator has put set-down weight on the “completion string” and also because internal pressure 22 will not pump the tool open, or faces 57 and 58 apart, because seals 50,51, 72, and 73 on Release Sleeve 55 balance the effects of internal pressure 22. As pressure 22 continues to act on Piston 106, Piston 106 continues to move upward until Expanding Lock Dogs 107 engage groove 108 and so Piston 106 is now locked to Lower Pickup Sleeve 49 and they will move together. Simultaneously, Lock Dog 109 engages groove 110 located in Release Sleeve 55. The shoulder 166 of Lock Dog 109 does not push on shoulder 165 of groove 110 of the Release Sleeve 55 at this time because shoulder 168 of lock dog 107 contacts shoulder 165 of groove 108 of the Lower Pickup Sleeve 49.

In Frac Module 146c, the piston length is such that when Piston 106 is locked in groove 108, pressure 22 is allowed to pass seal 104, move into chamber 54, and travel up hole 40 of Piston Housing 38. Pressure 22 can now act on seals 33 and 34 of Piston 32 to begin setting the packer or packing element 28. The Piston 32 causes face 31 of the Gage Ring 29 to begin compressing packing element 28 against face 30 of Push Sleeve 12. Compressive loads to compress packing element 28 can vary from as low as 10,000 pounds up to 50,000 pounds depending on the casing size and type of packer. This load is transmitted into Push Sleeve 12 to shear pins 8 and surface 30 moves up until Push Sleeve face 170 contacts Shear Ring 7 at face 171. At this point, recess 172 of Push Sleeve 12 allows pressure 22 to enter port 21, travel through recess 172 and into port 20 and into gun drilled hole 13. Gun drilled hole 13 is isolated with seals 4,5,15,16 and connects to hole 9 in Top Sub 1. Hole 9 has connector 10 that connects control line 11 which is the same as control line 117 that travels up to Frac Module 145b, see FIG. 3, and connects to fitting 116 and travels into hole 93, see FIG. 1c. Pressure 22 travels all the way up to Shift Piston 106 located in Frac Module 146b.

In Frac Module 146b, pressure 22 acts on seals 104 and 105 of Shift Piston 106 to shear pins 111 and move Shift Piston 106 upward. Upward movement of Shift Piston 106 releases Locking Keys 112 so that Lower Pickup Sleeve 49 and Upper Pickup Sleeve 56 are free to move until surfaces 57 and 58 make contact.

Although in Frac Module 146b, surfaces 57 and 58 will not make contact at this time because the operator has put set-down weight on the “completion string” and also because internal pressure 22 will not pump the tool open, or faces 57 and 58 apart, because seals 50, 51, 72, and 73 on Release Sleeve 55 balance the effects of internal pressure 22. As pressure 22 continues to act on Piston 106, Piston 106 continues to move upward until Expanding Lock Dogs 107 engage groove 108 and so Piston 106 is now locked to Lower Pickup Sleeve 49 and they will move together. Simultaneously, Lock Dog 109 engages groove 110 located in Release Sleeve 55. The shoulder 166 of Lock Dog 109 does not push on shoulder 165 of groove 110 of the Release Sleeve 55 at this time because shoulder 168 of lock dog 107 contacts shoulder 165 of groove 108 of the Lower Pickup Sleeve 49. In this Frac Module the length of Shift Piston 106 does not allow pressure 22 to pass seals 104 and 105, therefore the packer in Frac Module does not begin to set until workstring pickup occurs that allows pressure 22 to pass the seals 104 or 105 to get pressure to the packer setting piston. At this point the 146b Frac Module has been prepared for pickup to release the Flapper 79.

Going back to Frac Module 146c, pressure 22 is increased against the Flapper79 until packer setting load increases enough to shear Screws 6 in Ring 7. Push Sleeve 12 moves upward until faces 30 and 169 line up to create an anti-extrusion surface for packing element 28. Also, port 21 is isolated with seals 18 and 19. Pressure 22 is increased until full setting pressure 22 of the packer is reached. Full setting pressure 22 is controlled by Shear screws 86 that engage Seat Housing 83.

At this point, the Sliding Sleeve is fully opened and the packer is fully set and the upper Frac Module has an activated Flapper Release sleeve 55.

Pressure 22 is increased until Shear Screws 86 shear and the Flapper Assembly 79, 80, 81, 83 and related seals and shear pins, shift downward below the Frac Port 92 and set on top of Frac Sleeve 124 at a position below the bottom edge of the Frac Port windows. The flow path to and thru the Frac Ports is now fully open and zone 164 is ready for stimulation.

Once the stimulation is complete, it's time to treat the next upper zone 163. The workstring is picked up a distance “X”. This is when shoulders 57 and 58 make contact and during the movement thru distance “X” Lock Dog Shoulder 166 engages Release sleeve shoulder 165 which shifts Release Sleeve 55 upward. The Release Sleeve Finger 78 disengages Flapper 79 and allows Flapper 79 to close. The operator is now ready to begin operations on zone 163 as described above beginning at Reference point to repeat process.

The above process repeats for all zones. The pickup length “X” can be measured at the rig floor by marking pipe for each zone. The occurrence of length “X′ at the surface verifies that the Flapper 79 has been released in each zone. As zones are treated, “X” increases at the rig floor. If a Flapper 79 does not release, the Release Sleeve 55 may be shifted upward to release the Flapper 79 using a shifting tool that locates in profile 77 of Release Sleeve 55.

Claims

1) A full bore single trip multizone subterranean well treating apparatus, carriable into the well on a tubular workstring, said apparatus comprising:

(a) a tubular housing carried on said workstring and including a first fluid passageway therethrough;

(b) a plurality of treatment modules in securing relationship with said workstring, each said module being pre-determinedly spaced on said housing for operable alignment with a zone in said well to be selectively treated, each said module including: (1) a tubular housing member including a treatment fluid port therein and including a selectively communicable control chamber; (2) first and second sealing mechanisms on said tubular housing for isolating a selected first zone to be treated from another portion of said well; (3) a first full bore valving mechanism initially positioned within said housing in a full bore open position and selectively activatable to a closed position blocking fluid under pressure from being transmitted within said tubular housing and across said valving member; (4) first activation means for said first full bore valving means initially responsive to a first level of fluid pressure applied through said workstring and into said housing member and shiftable from a first inactive position to a second activated position, whereby said port is opened to place said chamber in fluid communication with said first fluid passageway of said tubular housing, and further whereby fluid pressure within said housing member above the said first level of fluid pressure activates said first sealing mechanism to set said first sealing mechanism in said well; (5) a second fluid flow passageway within said housing and including an initially blocked fluid port opening to the interior of said tubular housing, said blocked fluid port being opened to said tubular housing interior during activation of said first sealing means; and (6) second activation means responsive to fluid pressure in excess of the pressure required to activate the second sealing mechanism to isolate the said selected first zone from the well bore upstream of said selected first zone and thereafter, upon application of additional pressure within the tubular housing, to fully open said treatment port for transmission of a treating fluid within said tubular housing and into said selected first zone.

2) The apparatus of claim 1, further comprising in each of said modules positioned in said well upstream of the module for isolating the selected first zone to be treated from a second zone to be treated, full bore valving means initially positioned on said housing in an open position allowing fluid flow thereacross, and shiftable to a closed position in response to mechanical manipulation of said tubular workstring, whereby fluid flow across said valving means in said housing is sealingly blocked.

3) A single trip, full bore method for treating a plurality of zones within a subterranean well, comprising the steps of:

(a) introducing into the well a tubular workstring comprising: (1) a tubular housing carried on said workstring and including a first fluid passageway therethrough; (2) a plurality of zone isolation modules in securing relationship with said workstring, each said module being pre-determinedly spaced on said housing for operable alignment with a zone in said well to be selectively treated, each said module including: (i) a tubular housing member including a treatment fluid port therein and including a selectively communicable control chamber; (ii) first and second sealing mechanisms on said tubular housing for isolating a selected first zone to be treated from another portion of said well; (iii) a first full bore valving mechanism initially positioned within said housing in a full bore open position and selectively activatable to a closed position blocking fluid under pressure from being transmitted within said tubular housing and across said valving member; (iv) first activation means for said first full bore valving means initially responsive to a first level of fluid pressure applied through said workstring and into said housing member and shiftable from a first inactive position to a second activated position, whereby said port is opened to place said chamber in fluid communication with said first fluid passageway of said tubular housing, and further whereby fluid pressure within said housing member above the said first level of fluid pressure activates said first sealing mechanism to set said first sealing mechanism in said well; (v) a second fluid flow passageway within said housing and including an initially blocked fluid port opening to the interior of said tubular housing, said blocked fluid port being opened to said tubular housing interior during activation of said first sealing means; and (vi) second activation means responsive to fluid pressure in excess of the pressure required to activate the second sealing mechanism to isolate the said selected first zone from the well bore upstream of said selected first zone and thereafter, upon application of additional pressure within the tubular housing, to fully open said treatment port for transmission of a treating fluid within said tubular housing and into said selected first zone;

(b) increasing pressure in said tubular workstring and said tubular housing to a first level of fluid pressure to manipulate said first full bore valving mechanism to closed position and to simultaneously open said port;

(c) further increasing pressure in said tubular workstring and said tubular housing above the first level of pressure to activate the first sealing mechanism to set said sealing mechanism in the well and to simultaneously unblock and open said blocked fluid port;

(d) further increasing pressure in said tubular workstring and said tubular housing to activate the second sealing mechanism to sealing position in the well to isolate the said selected first zone from the wellbore upstream of said selected first zone; and

(e) further increasing fluid pressure in the tubular workstring and said tubular housing to fully open the treatment port for transmission of a treating fluid within said tubular housing and into said selected first zone.