US 20120103628A1
`
`(19) United States
`(12) Patent Application Publication (10) Pub. No.: US 2012/0103628 A1
`Stout
`(43) Pub. Date: May 3, 2012
`
`
`(54)
`
`METHOD AND APPARATUS FOR
`SINGLE-TRIP TIME PROGRESSIVE
`WELLBORE TREATMENT
`
`(75)
`
`Inventor:
`
`Gregg W. Stout, Montgomery, TX
`(1J3)
`
`(73)
`
`Assignee:
`
`OILTOOL ENGINEERING
`SERVICES, INC., Willis, TX (US)
`
`(21)
`
`Appl. No.:
`
`13/285,109
`
`(22)
`
`Filed:
`
`Oct. 31, 2011
`
`Related US. Application Data
`
`(60)
`
`Provisional application No. 61/408,780, filed on Nov.
`1, 2010.
`
`Publication Classification
`
`(51)
`
`Int. Cl.
`(2006.01)
`E213 34/06
`(2006.01)
`E213 34/00
`(52) U.S.Cl. ......................................... 166/373;166/319
`(57)
`ABSTRACT
`
`A single trip multizone time progressive well treating method
`and apparatus that provides a means to progressively stimu-
`late individual zones through a cased or open hole well bore.
`This system allows the operator to use pre-set timing devices
`to progressively treat each zone up the hole. At each zone the
`system automatically opens a sliding sleeve and closes a
`frangible flapper, at a pre-selected point in time. An adjust-
`able preset timing device is installed in each zone to allow
`preplanned continual frac operations for all zones. The appa-
`ratus is present as a “Frac Module” that can consist of three
`major components, a packer, a timing pressure device, and a
`sliding sleeve/isolation device. A hydraulic packer may be
`removed or replaced with a swellable type packer.
`
`
`
`Baker Hughes Ex. 2005
`Baker Hughes Ex. 2005
`Weatherford v. Baker Hughes
`Weatherford v. Baker Hughes
`IPR2019-00708
`Page 1 of 12
`Page 1 of 12
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`|PR2019—00708
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`

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`Patent Application Publication
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`May 3, 2012 Sheet 1 of 5
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`US 2012/0103628 A1
`
`May 3, 2012
`
`METHOD AND APPARATUS FOR
`SINGLE-TRIP TIME PROGRESSIVE
`WELLBORE TREATMENT
`
`[0001] This application claims priority to US. provisional
`application Ser. No. 61/408,780 filed on Nov. 1, 2010.
`
`BACKGROUND OF INVENTION
`
`1. Field of the Invention
`[0002]
`[0003] The present invention relates to apparatus and meth-
`ods for oil and gas wells to enhance the production of subter-
`ranean wells, either open hole, cased hole, or cemented in
`place and more particularly to improved multizone stimula-
`tion systems.
`[0004]
`2. Description of RelatedArt
`[0005] Wells are drilled to a depth in order to intersect a
`series of formations or zones in order to produce hydrocar-
`bons from beneath the earth. Some wells are drilled horizon-
`
`tally through a formation and it is desired to section the
`wellbore in order to achieve a better stimulation along the
`length of the horizontal wellbore. The drilled wells are cased
`and cemented to a planned depth or a portion ofthe well is left
`open hole.
`[0006]
`Producing formations intersect with the well bore in
`order to create a flow path to the surface. Stimulation pro-
`cesses, such as fracing or acidizing are used to increase the
`flow ofhydrocarbons through the formations. The formations
`may have reduced permeability due to mud and drilling dam-
`age or other formation characteristics. In order to increase the
`flow ofhydrocarbons 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 ofthe 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 casing that communicates with the formation or
`sometimes open hole. In order to direct a treatment fluid
`through a frac port and into the formation, a seat or valve may
`be placed above 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.
`[0007] One method, furnished by PackersPlus, 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 because the ball is so weak,
`so the ball blows through the seat. Furthermore, the small ball
`seats reduce the ID. ofthe production flow path which creates
`other problems. The small I.D. prevents re-entry of other
`downhole devices, i.e., plugs, running and pulling tools, shift-
`ing 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.
`[0008] The size of the ball seats and related balls limits the
`number of zones that can be treated in a single trip. Further-
`more, the balls have to be dropped from the surface for each
`zone and gravitated or pumped to the seats.
`[0009] Another method, used by PackersPlus, US. Pat. No.
`7,543,634 B2, places sleeves in the ID. of the tubing string.
`These sleeves cover the frac ports and packers are placed
`above and below the frac ports. Varying sizes ofballs or plugs
`are dropped on top of the sleeves and when pressuring 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 offbefore the sleeve
`is fully opened. If the ball and sleeve remain in the flow path,
`the flow path is restricted for the frac operation.
`[0010]
`It would be advantageous to have a system that had
`no ball seats that restrict the ID. ofthe 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 opera-
`tion. Also, it would be beneficial to have a system that auto-
`matically fully opens each sliding sleeve and isolates the zone
`below, progressively up the well bore, before each zone is
`stimulated. Such a system allows stimulation of one zone at a
`time to achieve the maximum frac efficiency for each zone. In
`addition, it would be advantageous to be able to, in the future,
`isolate any zones by closing a sliding sleeve. For example, a
`single zone could be shut off if it began producing water or
`became a theft zone.
`
`Furthermore, it would be greatly advantageous to
`[0011]
`eliminate the time and logistics required for dropping numer-
`ous balls into the well, one at a time, for each zone in the well
`to be treated. It would also be advantageous to have a multi-
`zone frac system that functioned automatically while all
`zones were being stimulated in order to minimize the time
`surface pumping equipment is setting idol between pumping
`zones.
`
`[0012] Many wells are being stimulated at multiple zones
`through the well bore by use of composite plugs such as the
`“Halliburton Obsidian Frac Plug” or the “Owen Type ‘A’ Frac
`Plug”. A composite plug is set near, or below, a zone and then
`the zone is treated. Another composite plug is set in the next
`upper zone and that zone is treated, and so on up the well bore
`until multiple plugs remain in the well. The composite plugs
`are then drilled out which can be time consuming and expen-
`sive. The shavings from the mill operation leave trash in the
`well and can also plug of flow chokes at the surface. It would
`be advantageous to have a system that eliminated the use and
`drilling out of composite or millable plugs. Of course, this
`approach would apply to new well completions where equip-
`ment, of the present invention, could be placed into the well
`prior to treating.
`[0013] Other well completions, such as intelligent wells,
`are designed to operate downhole devices by use of control
`lines running from the surface to various downhole devices
`such as packers, sleeves, valves, etc. An example of this type
`of system can be found in Schlumberger US. Pat. No. 6,817,
`410 B2. This patent describes use of control lines and the
`various devices they operate. It is obvious the use of control
`lines can make the completion very complicated and expen-
`sive. The present invention allows operation of some types of
`downhole devices possible without the use of control lines.
`
`Page 7 of 12
`Page 7 of 12
`
`

`

`US 2012/0103628 A1
`
`May 3, 2012
`
`For example, the present invention describes a timer/pres sure
`device that could be placed both above and below a sliding
`sleeve, and days, months, or even years later, a sliding sleeve,
`or series of sliding sleeves, could be programmed to open or
`close.
`
`[0014] There are other wells that sometimes require well
`intervention. A product called a Well Tractor, supplied by
`Welltec, is used to aid in shifting sliding sleeves opened or
`closed in long horizontal wells or highly deviated wells,
`sometimes in conjunction with wireline or coiled tubing
`operations. The present invention offers an alternate and more
`economical solution to functioning downhole devices in
`wells without well intervention.
`
`BRIEF SUMMARY OF THE INVENTION
`
`[0015] This invention provides an improved multizone
`stimulation system to improve the conductivity of the well
`formations with reduced rig time, no milling, and no control
`lines from the surface and, for some other applications,
`reduce well intervention. The equipment for all zones can be
`conveyed in single work string trip and frac units can stay on
`location one time to treat all zones.
`
`[0016] This invention relates to an automatic progressive
`stimulation system where no control line or ball drop appa-
`ratus are needed. This system can also eliminate the need to
`set and mill out composite plugs in newly planned well
`completions. When single zone or multiple zone wells are to
`be completed with plans of stimulation and then producing,
`the equipment in the present invention can be utilized. This
`invention is comprised of three major components; a packer,
`a timer/pressure device, and a sliding sleeve/valve assembly.
`Although, in some cases, a packer may not be needed. The
`combination of these three components has been given the
`name “Frac Module”.
`
`I. The packer can be several types, such as those that
`[0017]
`set hydraulically by applying tubing pressure, those that are
`Swellable, or those that are Inflatable, to mention a few.
`[0018]
`II. The timer/pressure device is a device that can be
`actuated by application of well pressure such as tubing pres-
`sure or annulus pressure. This pressure can act on a pressure
`sensitive device, which in turn triggers a timing device where
`the timing device can be set to any desired time, before it
`triggers a pressure generating device which is turn applies
`pressure to a downhole tool in order to activate the tool.
`[0019]
`III. The sliding sleeve is a typical type sleeve that
`can open or close a port, or series of ports, that allow fluids or
`slurries to travel down the well conduit, through the ports, and
`communicate with the formation. For the present invention,
`the sliding sleeve would be of the piston type where pressure
`acts on a piston and in turn shifts the sleeve. A frangible
`flapper valve, or other type of valve, is positioned above the
`sliding sleeve and closes when the sliding sleeve shifts down-
`ward. The valve directs flow through the ports in the sliding
`sleeve and isolates the zone below.
`
`[0020] A series of frac modules placed in the well act in
`unison, where all packers are set at once and all timers/
`pressure devices are triggered at once, with a single applica-
`tion of tubing pressure. Each timer in each zone can be set to
`a desired time so that, for example, the lowermost timer
`actuates a pressure generating device after one hour from the
`time when tubing pressure was initially applied. The pressure
`generating device creates pressure that comm1micates with a
`piston on the sliding sleeve to open the sliding sleeve and
`
`close the flapper valve. This first zone is treated through the
`sliding sleeve ports before the next upper sliding sleeve
`opens.
`[0021] The next upper Frac Module timer is set for 2 hours,
`for example, from the time when initial tubing pressure was
`applied. At the end of the two hour time period, the timer
`actuates a pressure generating device to open its sliding sleeve
`so the zone can be treated. Timers in each zone can be set to
`
`the desired time to allow stimulating as many zones as
`required.
`[0022] The timing devices can be set so that all zones can be
`nearly continuously treated in order to optimize the use of
`surface stimulation equipment. The timers are versatile
`enough where all the timers can be triggered at once. A
`portion of timers can be triggered at one selected pressure
`while others are triggered at different selected pressures, or
`sequences of applied pressures.
`[0023]
`To those familiar with the art ofwell completions, it
`is obvious that the scope ofthis invention is not limited to just
`timer/pressure generating devices shifting sliding sleeves
`open or closed but can also be used to actuate any type or
`combination of a downhole tool device, or devices, in any
`timing sequence, such as perforating guns, valves, packers,
`etc. More than one timing/pressure device can be used to
`function a single type multiple times by setting the timers at
`different time spans.
`
`BRIEF DESCRIPTION OF THE SEVERAL
`
`VIEWS OF THE DRAWING(S)
`
`FIGS. 1, 2, and 3 placed end-to-end make up a
`[0024]
`schematic view of an embodiment of the present invention.
`[0025]
`FIG. 4 is a schematic view of three Frac Modules
`assembled in tandem in a well completion.
`[0026]
`FIG. 5 is a schematic showing a second embodiment
`of a timer/pressure device that can be used in the Frac Mod-
`ule.
`
`DETAILED DESCRIPTION OF THE PREFERRED
`EMBODIMENTS
`
`[0027] With reference to FIG. 1, a schematic of an embodi-
`ment of the present invention shows a 90 degree lengthwise
`cross-section ofthe apparatus. This portion ofthe apparatus is
`a simplified view ofa tubing pressure hydraulically set packer
`2, although packers such as swell and inflatable packers may
`be used. A packer maybe used that has a slip system added and
`a packer may be used that has a release device added.
`[0028] Tubing string 1 has a connecting thread 3 that con-
`nects to top sub 4. Top sub 4 threadably connects to packer
`mandrel 7. Packing element 5 and gage ring 6 are positioned
`over Mandrel 7. Ratchet ring 8 is located and threadably
`locked inside housing 9. Piston 10 is threadably connected to
`gage ring 6 and ratchet ring 8 engages piston thread 96 as
`piston 10 strokes upward (left end of drawing). Seals 11 and
`12 form a seal in bores 97 and 98 and between piston 10.
`Tubing pressure 52 enters port 14 and acts across seals 11 and
`12 to move piston 10 upward compressing packing element 5.
`Fluid is displaced through port 16. Ratchet ring 8 locks piston
`10 so the packing element 5 stays compressed and sealed
`inside outer casing 99. Housing 9 has pin thread 13 facing
`downward.
`
`[0029] Referring to FIG. 2, the timer/pressure assembly 18
`is shown in a schematic, This schematic illustrates a totally
`mechanical timing/pressure device although other types of
`
`Page 8 of 12
`Page 8 of 12
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`

`

`US 2012/0103628 A1
`
`May 3, 2012
`
`devices can be substituted such as a pressure sensitive pres-
`sure transducer interconnected to an electronic timer that
`
`initiates a pyrotechnics gas pressure generating device, for
`example. Such a device is shown in FIG. 5.
`[0030] Referring to the schematic, thread 17 of pin 13 con-
`nects to outer chamber 19. Inner chamber 20 is trapped inside
`outer chamber 19 to form an annular space between the two
`chambers. Piston 25 has seals 23 and 24 that seal inside of
`
`inner and outer chambers 19 and 20. Tubing pressure 52
`enters port 21 and chamber 22 to act on piston 25. The top end
`of compression spring 29 is shown in a near solid height
`condition where spring 29 makes solid contact with piston 25
`at location 28.
`
`[0031] The bottom end of compression spring 29 makes
`solid contact with Orifice piston 33 at location 30. Shear
`screws 31 shearably connect orifice piston 33 to inner cham-
`ber groove 100. Piston 25 is allowed to stroke downward until
`face 26 contacts shoulder 27.
`
`[0032] A flow control device, such as a LEE Visco Jet 32 is
`located inside of orifice piston 33 so that fluid, such as sili-
`cone oil, located in chamber 39 can only pass thruVisco Jet 32
`anc into chamber 40. Seals 34 and 35 seal orifice piston 33 on
`the inside walls of chamber 39. Orifice piston 33 has face 36
`tha travels through chamber 39 to make contact with face 37
`of pressure release rod 38. Pressure chamber 48 is threadably
`connected to outer chamber 19 at thread 50. Seals 42 and 49
`
`
`
`iso ate chamber 45 where chamber 45 is charged with a
`pressurized gas, such as nitrogen. Seals 41 on both ends of
`pressure release rod 38 also isolate chamber 45 to hold pres-
`sur'zed gas within the chamber. Chamber 39 communicates
`with chamber 44 through gap 47.
`[0033] Bores 46 inside of pressure chamber 48 are of near
`eqL al, or equal, diameter and seals 41 are of near, or equal,
`dia neter so that pressure release rod 38 is in the pressure
`balanced condition when exposed to pressure from either
`chambers 39 or 45. Pressure release rod 38 is held relative to
`
`chamber 48 by a low force spring loaded detent ball 101 to
`prevent pressure release rod 38 from moving until contacted
`by orifice piston face 36.
`[0034] Chamber 45 is charged with high pressure nitrogen
`gas through nitrogen charge valve 58 and longitudinal hole
`53. Hole 53 is sealed off at one end with plug 56 but is open
`to chamber 45 at the opposing end. Seals 59 and 60 seal the
`nitrogen charge valve 58 in order to prevent passage ofgas out
`of chamber 45 and past the valve 58.
`[0035] A doughnut sleeve with internal o-rings and a sealed
`allen wrench, not shown, slides over nitrogen charge valve 58
`to allow unscrewing Valve 58 to allow passage of gas through
`the doughnut and into chamber 45. Once chamber 45 is at the
`desired pressure, the valve 58 is closed with the allen wrench
`to seal the chamber 45.
`
`[0036] Upper sleeve housing 68 is threadably attached to
`chamber 48 with thread 61 and sealed with seals 62. Longi-
`tudinal hole 54 communicates with chamber 44, not exposed
`to charged gas pressure at this time, and chamber 55 and hole
`57. Seals 63 isolate chamber 55 from pressure 52. Seals 51
`isolate pressure 52 from chambers 39 and 44.
`[0037]
`Pressure release rod 38 has recesses 43 and 102 so
`when shifted downward by spring force in spring 29 and face
`36, seal 41 leave seal bore 46 and pressurized gas can move
`from inside chamber 45 to chamber 55 and into hole 57.
`
`Frangible flapper valve 65 is mounted by axle 66
`[0038]
`and is spring biased with spring 67 to rotate from the open
`position, shown, to the dosed position. Finger 64 temporarily
`
`holds the Flapper 65 in the open position. Axle 66 is posi-
`tioned on the upstream portion of sleeve 71 and is carried by
`it.
`
`[0039] Referring to FIG. 3, this schematic shows ported
`sliding sleeve 95. Upper sleeve housing 68 shows the con-
`tinuation of hole 57 that communicates with chamber 72.
`
`Sleeve piston 76 has seal 74 and 75 that isolate chambers 72
`from 77. Screw 73 connects piston 76 to sleeve 71. Seal 69
`isolates chamber 72 from pressure 52 and seal 80 isolates
`chamber 77 from pressure 52. Seals 69 and 80 are ofthe same
`diameter so that sleeve 71 is pressure balanced, or near pres-
`sure balanced from pressure 52 so pressure 52 does tend to
`move sliding sleeve 71 up or down. Gas pressure in chamber
`72 acts on piston 76 to move sliding sleeve 71 downward or to
`the open position.
`[0040]
`Single or multiple ports 70 go through the wall of
`upper sleeve housing 68 and sleeve 71 and seals 69 and 80
`prevent pressure or fluid from traveling from location 103,
`through ports 70 and to location 1 04, or vice versa. Ifpres sure
`in chamber 72 is greater than pressure in chamber 77 and
`pressure acts on piston 76, the piston 76 and sliding sleeve 71
`will move downward toward chamber 77. During this move-
`ment, fluid exits ports 78 and 79 to area 104. When seal 74
`passes port 78, gas pressure above piston 76 and in chamber
`72 passes through port 78 allowing the gas pressure to equal-
`ize.
`
`[0041] Downward movement of sleeve 71 allows seal 69 to
`move past port 70 so that flow passage can occur from area
`103 to area 104. Also, when the sliding sleeve 71 moves
`downward, flapper 65 moves away from finger 64 and rotates
`around axle 66 allowing spring 67 to rotate flapper 65 to the
`closed position.
`[0042] Collets 88 and 89 are common to sliding sleeves and
`come in different geometries. The collets lock the sliding
`sleeve 71 either in the up or down position in recesses 87 and
`90. Shifting tool profiles are added to the inside of the sliding
`sleeve 71 to use mechanical shifting tools run on wireline or
`tubing, to shift the sliding sleeve 71 closed or back open at
`some future time.
`
`Sleeve housing 83 is threadably connected to upper
`[0043]
`sleeve housing 68 with thread 81. A stop key 85 may be
`employed to engage shoulder 86 to stop the downward move-
`ment of sliding sleeve 72 as to not load collets 88 and 89 in
`compression. Stop key 85 sets in pocket 82 and can move
`downward in slot 84.
`
`[0044] Bottom sub 93 is threadably attached to sleeve hous-
`ing 83 with thread 91 and is sealed with seals 92. Pin thread 94
`connects to a tubing spacer which in turn connects to another
`Frac Module or possibly a bottom locator seal assembly that
`stings into a sump packer.
`[0045] Referencing FIG. 4, this schematic shows a possible
`completion hookup 105 using three Frac Modules 106, 107,
`and 108 although many Frac Modules may be used. The well
`has casing 116 and below location 127 the well casing 116
`can continue or the well can be open hole passing through
`zones 111, 112, and 113. Packers 117, 118, and 119 can be
`tubing pressure hydraulic set packers for cased hole or
`swellable or tubing pressure set inflatable packers for either
`cased hole or open hole. Each zone can have a timer/pressure
`device 122, 121, and 120 and a ported sliding sleeve valve
`assembly 125, 124, and 123. Each zone can be separated by
`tubing spacers 114 and tubing 115 runs to the surface or a
`hydraulic set production packer (not shown). A sump packer
`109 can be set prior to running the completion string of frac
`
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`US 2012/0103628 A1
`
`May 3, 2012
`
`modules. The bottom of the completion string can have a
`typical locator seal assembly 110 that stings into sump packer
`109. If it is desired not to run a sump packer 109, the sump
`packer can be replaced with an additional tubing pressure set
`hydraulic packer that is set by dropping a ball on a seat below
`the packer. In either case, all tubing pressure set packers will
`set at the same time, if desired. Each zone is isolated with
`packers set above and below each zone and the sliding sleeves
`in the closed position.
`this is a schematic of an
`[0046] Referring to FIG. 5,
`embodiment of the present
`invention showing a second
`method ofproducing pressure to shift a sliding sleeve or other
`downhole device. Referencing FIG. 2, this device can be put
`in the place of the device described in FIG. 2.
`[0047] Once again, there is an outer chamber 19, an Inner
`chamber 20, a port 21, a chamber 22, seals 23 and 24, a
`chamber 44, and a hole 57. Pressure from area 52 enters port
`21 into chamber 22 and into hole 129. Pressure in hole 129
`
`acts on a pressure sensitive device, such as a pressure trans-
`ducer 130. The pressure transducer triggers a switch 131 that
`starts an adjustable timer 132 that is set for a time frame, say
`4 hours. The timer can be pre-set at the surface prior to
`running the tools into the well. The timer can be set for any
`time increment desired, for example from 1 minute to 100
`hours, or longer. At the end of 4 hours it triggers a switch 133
`to supply battery power 134 to an Igniter 135, or initiator. The
`battery power can also run the timer or the timer can be purely
`mechanical. Power supplied to the igniter 135 triggers the
`igniter 135, or initiator, to cause the material in the gas gen-
`erator 136 to burn, react, or mix, and produce high pressure
`gas. The high pressure gas pressure increases in chamber 44,
`travels through hole 57 to act on the piston 76, shown in FIG.
`3. Pressure on the piston 76, shifts the sliding sleeve 71 to the
`open, or down, position. Components 130, 131, 132, 133,
`134, 135, and 136 can be moved, or substituted with other
`mechanisms, to different relative positions to achieve the
`same goal of producing gas pressure. These components can
`be in a single cartridge modular form, say one assembly, and
`can be miniaturized or improved by use of microelectronics.
`Also, more than one timer/pressure device can be used for
`redundancy and reliability purposes.
`[0048] The device in FIG. 5, and the device in FIG. 2,
`illustrate that more than one technique can be used to create a
`timer/pres sure device, and the present invention is not limited
`to one technique.
`[0049]
`Furthermore, it is important to recognize that the
`timer/pressure device described in FIGS. 2 and 5 can be
`positioned relative to the sliding sleeve, FIG. 3, either above
`or below the sliding sleeve, although if the timer/pressure
`device were positioned below the sliding sleeve, the hole 57
`arrangement would be slightly more complicated when shift-
`ing the sleeve upward. A first timer/pressure device can be
`used to open the sleeve and a second timer/pressure device
`can be positioned below the sliding sleeve to close the sliding
`sleeve at a specified time in the future.
`
`Description of Operation
`
`[0050] With reference to the example in FIG. 4, a typical
`completion is shown but many variations of this occur as
`known by those who are familiar with the variations that
`occur in configuring well completions.
`[0051] A well has been drilled, cased, cemented, and per-
`forated, although this system may be used in open hole
`completions with selection ofthe appropriate packers. Casing
`
`116 is shown in this example with zones and perforations 111,
`112, and 113 in the casing. The objective is to stimulate all of
`the zones 111, 112, and 113 in a single trip without well
`intervention. A sump packer 109 is properly located and set
`below the lowermost zone 113 although this packer may be
`substituted with a packer similar to packer 119 by landing a
`ball against a seat below where packer 109 is shown.
`[0052] A “completion string” is run into the well consisting
`of a locator snap latch seal assembly 110, tubing spacer 114,
`frac module 108, tubing spacer 114, frac module 107, tubing
`spacer 114, frac module 106, tubing spacer 114, a service/
`production packer (not shown), and work string or production
`115. The length oftubing spacers 114 are made to position the
`frac modules 106, 107, and 108 between the producing zones
`111, 112, and 113.
`[0053] The single trip completion string is landed in sump
`packer 109. The location of sump Packer 109 is based on logs
`of the zones so that all equipment could be spaced out prop-
`erly. Therefore, by locating the completion assembly on the
`sump packer 109, all Frac Modules 106, 107 and 108 will be
`properly positioned in the well. Snap latch seal assembly 110
`can be used to verify position of the system before setting any
`of the packers 117, 118, and 119. The locator snap latch seal
`assembly 110 seals in the sump packer 109 and will locate on
`the sump packer. The locator snap latch seal assembly 110 is
`designed to allow pulling of the work string 115 to get a load
`indication on the sump packer 109 and then snap back in and
`put set-down weight on the sump packer 109. The above steps
`are common in the art of completing wells.
`[0054] At this point in time the completion hardware,
`shown in FIG. 4, is properly positioned around all the zones to
`be stimulated. All stimulation equipment has been positioned
`around the well at the surface and all frac lines have been
`
`assembled and pressure tested. A pumping company has done
`stimulation pre-planning for each zone and has all the neces-
`sary materials ready to pump, along with backup surface
`units. The Frac Modulc Timcrs were all set prior to running
`the system into the well but at this point in time, none of the
`timers have been actuated. The pumping company knows
`how long it will take to pump each zone and the timers were
`pre-set based on how long it will take to frac each zone. The
`timers were pre-set to allow extra time for any required sur-
`face operations during the overall process.
`[0055] Now that the completion system is in the proper
`position in the well and all surface equipment has been
`nippled-up, the zones are ready to stimulate.
`[0056] At this point all the sliding sleeves in each Frac
`Module are in the closed position. The operator may decide to
`do a low pressure system pressure test at this time before
`actuating any downhole devices. The entire system is pres-
`sured up, for example, to 500 psi and held for a period of time
`until there is proof of no leaks in the system.
`[0057] At this point all surface equipment is running and
`the well is ready to stimulate. The first step is to set all of the
`packers, assuming that they are hydraulic tubing pressure set
`packers. If they are swellable packers, the operator will wait
`to begin operations until all ofthe Swellable packers have had
`time to swell.
`
`[0058] Continuing and assuming the packers are tubing
`pressure set, the surface pump units begin applying tubing
`pressure 126 inside of work string 115 to packer setting ports
`14. All of the packers may be designed to begin setting at
`
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`US 2012/0103628 A1
`
`May 3, 2012
`
`1,500 psi and may not fully set until the tubing pressure
`reaches 3,500 psi, for example. This pressuring operation will
`take several minutes.
`
`[0059] The same pressure 52 used to set the packers 11