Abstract:
A single trip multizone time progressive well treating method and apparatus that provides a means to progressively stimulate individual zones through a cased or open hole well bore. The operator can 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 preselected point in time. An adjustable preset timing device is installed in each zone to allow preplanned continual frac operations for all zones. An optional “Stand-Down-Mode” can be integrated into the timing system so that if pumping stops the timers go into a sleep mode until the pumping resumes. The apparatus can consist of three major components: a packer, a timing pressure device, and a sliding sleeve/isolation device. The packer may be removed.

Description:
This application is a Continuation-in-Part of U.S. patent application Ser. No. 13/285,109 filed Oct. 31, 2011 which claims priority to U.S. provisional application Ser. No. 61/408,780 filed on Nov. 1, 2010. 
    
    
     BACKGROUND OF 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, cased hole, or cemented in place and more particularly to improved multizone stimulation systems. 
     2. Description of Related 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. Some wells are drilled horizontally 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 of the well is left open hole. 
     Producing formations intersect with the well bore in order to create a flow path to the surface. Stimulation processes, such as fracing or acidizing 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 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. 
     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&#39;t get adequate pressure to frac the zone because the ball is so wreak, so the ball blows through the seat. Furthermore, the small ball seats reduce the I.D. of the production flow path which creates other problems. The small I.D. prevents re-entry of other downhole devices, i.e., plugs, miming 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 ran is needed to mill out ail 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. Furthermore, the balls have to be dropped from the surface for each zone and gravitated or pumped to the seats. 
     Another method, used by PackersPlus, U.S. Pat. No. 7,543,634 B2, 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 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 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 automatically 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 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. It would also be advantageous to have a multizone 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. 
     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 expensive. The shavings from the mill operation leave trash in the well and can also plug off 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 equipment, of the present invention, could be placed into the well prior to treating. 
     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 Patent U.S. 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 expensive. The present invention allows operation of some types of downhole devices possible without the use of control lines. For example, the present invention describes a timer/pressure 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. 
     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 oilers an alternate and more economical solution to functioning downhole devices in wells without well intervention. 
     BRIEF SUMMARY OF THE INVENTION 
     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. 
     This invention relates to an automatic progressive stimulation system where no control line or ball drop apparatus 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, for example, if the system is cemented in place. The combination of these three components, or two components without the packer, has been given the name “Frac Module”. 
     I. The packer can be several types, such as those that set hydraulically by applying tubing pressure, those that are Swellable, or those that are Inflatable, to mention a few. 
     II. The timer/pressure device is a device that can be actuated by application of well pressure such as tubing pressure or annulus pressure. This pressure can act on a pressure sensitive device, which in turn triggers a timing device where the timing device, or a plurality of timing devices, 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. 
     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 downward. The valve directs flow through the ports in the sliding sleeve and isolates the zone below. 
     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 application 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 communicates 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. 
     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. 
     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. A further option includes a pressure sensitive device that is attached to or built into each timing device, which monitors well pressure so that when well pressure reaches a predetermined level, the timers go into a “Stand-Down-Mode”. Surface applied well pressure can be in the form of a series of pressure increase or decreases in conjunction with pressure holds or simply a decrease in pressure to a pre-selected level. For example, if frac pumping is in process and all of the timers are running, if the frac operation stops for some reason and frac pressure drops below a selected point, all of the timers go into a “Stand-Down-Mode” where the timers stop temporarily. The timers remember the time used up to that point and when pump pressure resumes, all of the timers begin running once again for the balance of the time remaining in each timer. All of the timers remain in their preprogrammed sliding sleeve activation sequence. 
     To those familiar with the art of well completions, it is obvious that the scope of this 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 schematic view of an embodiment of the present invention. 
         FIG. 4  is a schematic view of three Frac Modules assembled in tandem in a well completion. 
         FIG. 5  is a schematic showing a second embodiment of a timer/pressure device that can be used in the Frac Module. 
         FIG. 6  is a schematic showing a third embodiment of a timer/pressure device that includes a “Stand-Down-Mode” device that can be used in the Frac Module. 
         FIG. 7  is a schematic showing a fourth embodiment of a timer/pressure device that is a modification of the device in  FIG. 5  where a “Stand-Down-Mode” device has been added. 
         FIG. 8  is a well schematic showing an embodiment of a Frac Module without any packers where the entire system is cemented in place. 
     
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
     With reference to  FIG. 1 , a schematic of an embodiment of the present invention shows a 90 degree lengthwise cross-section of the apparatus. This portion of the apparatus is a simplified view of a 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. 
     Tubing string  1  has a connecting thread  3  that connects 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. 
     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 devices can be substituted such as a pressure sensitive pressure transducer interconnected to an electronic timer that initiates a pyrotechnics gas pressure generating device, for example. Such a device is shown in  FIG. 5 . 
     Referring to the schematic, thread  17  of pin  13  connects 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 . 
     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 chamber groove  100 . Piston  25  is allowed to stroke downward until face  26  contacts shoulder  27 . 
     A flow control device, such as a LEE Visco Jet  32  is located inside of orifice piston  33  so that fluid, such as silicone oil, located in chamber  39  can only pass thru Visco Jet  32  and into chamber  40 . Seals  34  and  35  seal orifice piston  33  on the inside walls of chamber  39 . orifice piston  33  has face  36  that 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  isolate 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 pressurized gas within the chamber. Chamber  39  communicates with chamber  44  through gap  47 . 
     Bores  46  inside of pressure chamber  48  are of near equal, or equal, diameter and seals  41  are of near, or equal, diameter 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 . 
     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 of gas out of chamber  45  and past the valve  58 . 
     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 . 
     Upper sleeve housing  68  is threadably attached to chamber  48  with thread  61  and sealed with seals  62 . Longitudinal 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 . 
     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  and is spring biased with spring  67  to rotate from the open position, shown, to the closed position. Finger  64  temporarily holds the Flapper  65  in the open position. Axle  66  is positioned on the upstream portion of sleeve  71  and is carried by it. 
     Referring to  FIG. 3 , this schematic shows ported sliding sleeve  95 . Upper sleeve housing  68  shows the continuation 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 of the same diameter so that sleeve  71  is pressure balanced, or near pressure 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. 
     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  104 , or vice versa. If pressure 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 movement, 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 equalize. 
     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. 
     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 sleeve housing  68  with thread  81 . A stop key  85  may be employed to engage shoulder  86  to stop the downward movement 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 . 
     Bottom sub  93  is threadably attached to sleeve housing  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. 
     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 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 ran 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. 
     Referring to  FIG. 5 , this is a schematic of an embodiment of the present invention showing a second method of producing 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 . 
     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 transducer  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 generator  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. 
     The device in  FIG. 5 , and the device in  FIG. 2 , illustrate that more than one technique can be used to create a timer/pressure device, and the present invention is not limited to one technique. 
     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 shifting 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. 
     Referring to  FIG. 6 , this is a schematic of an embodiment of the present invention showing a third method of producing pressure to shift a sliding sleeve or activate other downhole devices. Tubular section  9  has thread  17  that connects to top sub  137 . Piston housing  146  threadably connects to top sub  137  at thread  138 . Piston  143  is positioned inside of piston housing  146  and top sub  137  and seals  141 ,  142  and  144  form pressure seals at bores  169 ,  170 , and  171  around piston  143 . Chamber  177  is either an atmospheric chamber if port  140  is plugged or is exposed to pressure external to the tool through port  140  if port  140  is not plugged. Shear screws  145  shearably lock piston  143  to a groove  168  in top sub  137 . Seals  141  and  142  prevent pressure at  52  from traveling thru hole  139  and to pressure in port  140 . Seals  142  and  144  prevent pressure at  52  from traveling thru hole  139  and into hole  178  and on into chamber  151 . Inner housing  155  is threadably connected to piston housing  146  with thread  148  and sealed with seal  149 . Outer housing  172  is threadably connected to piston housing  146  with thread  147  and sealed with seal  150 . Positioned inside housings  172  and  155  is a pressure sensitive device  152 , which may be a pressure transducer, a switch  154 , a timer  156 , a switch  157 , a battery pack  158  all of which control a metal piercing device  159 . The metal piercing device forms a hole in membrane  162  and may be a drill, punch, or an explosive squib that is designed to perforate metal. The Figure shows an electric powered motor  159  with a drill  161  with a spring  160  that forces the drill  161  against membrane  162  as to create communication with pressurized gas chamber  45 . Of course the motor  159 , can be replaced with an electrical detonated explosive squib that is designed to form small hole in metal. The squib would be similar to a DuPont Electronic Detonator Type “S”. Pressure transducer  152  has seals  173  and  153  that seal near chamber  151  to prevent pressure or fluids in chamber  151  from traveling through gap  47  and into chamber  44  and hole  57 . Components  152 ,  154 ,  156 ,  157 ,  158  and  159  can be rearranged, simplified, or compacted so that when the pressure transducer is activated by pressure  52 , the timer begins running and turns the piercing device on after a programmed period of time. Also, a plurality of these components can be used to create redundancy in the system. A second pressure sensitive device  164  is also in communication with hole  143 . Programmable controller  165  has the logic to turn switch  166  on or off based on the status of the pressure at  52 . Wires  163  attach to timer circuitry  156  so that switch  166  can stop timer  156 , where timer remembers time already spent, and restarts timer for the remaining un-spent time, commonly called the “Stand-Down-Mode”. This “Stand-Down-Mode” device can also be powered by battery  158 , if desired, or have its own battery. The “Stand-Down-Mode” device can also be built as part of the components  152 ,  154 ,  156 ,  157 ,  158 , and  159 . Controller  165  has programmable logic that senses the status of pressure  52  where controller  165  can be set to sense a threshold pressure at  52  where the threshold pressure is the pressure that would exist if all pressure pumping from the surface ceased. The threshold pressure could be calculated based on the static bottom-hole-pressure plus a minimal applied pressure, say 500 PSI or 1000 PSI. If bottom-hole-pressure is 5000 PSI then the threshold pressure, pre-programmed into all of the timers, could be 6,000 PSI at the timer pressure transducers. When pressure dropped equal to or less than the threshold pressure, all of the timers in the system would go into the “Stand-Down-Mode” until pressure pumping was resumed to increase pressure above the threshold pressure. The logic in controller  165  could also be set to respond to a series or plurality of pressure pulses of varying magnitudes and durations in order to put the timers into the “Stand-Down-Mode” and a second series of pressure pulses to remove the timers from the “Stand-Down-Mode”. All timers  156  would go to and from the “Stand-Down-Mode” in unison as to preserve the overall zone-by-zone timing sequence that is preprogrammed into the system for sequential tracing of all zones. The remaining components in  FIG. 6  are the same ones shown in  FIG. 2  except that the chamber  45  is now a sealed chamber in order to reduce potential leak paths, i.e., no rod  38  with seals  41 . Rather than shifting rod  38  to release pressurized gas in chamber  45 , the membrane  162  is ruptured to release the pressurized gas into hole  57  that in turn acts on the sliding sleeve piston  76 , of  FIG. 3 , to activate the sliding sleeve  71 . 
     Referring to  FIG. 7 , this is a schematic identical to  FIG. 5  except that the controller  167  has been added in the circuitry to provide a “Stand-Down-Mode”, if desired. 
     Referring to  FIG. 8 , this is a well schematic similar to  FIG. 4  except that the packers  117 ,  118 , and  119  have been removed from the Frac Modules and also the tools are placed in an open hole section of the well where the open hole  175  is filled with cement  176 . Also, in a cemented completion, there is no need for the sump packer  109  or locator  110 . 
     DESCRIPTION OF OPERATION 
     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. 
     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  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. 
     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 of tubing spacers  114  are made to position the frac modules  106 ,  107 , and  108  between the producing zones  111 ,  112 , and  113 . 
     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 properly. 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. 
     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 necessary materials ready to pump, along with backup surface units. The Frac Module Timers 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 surface operations during the overall process. 
     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. 
     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 pressured up, for example, to 500 psi and held for a period of time until there is proof of no leaks in the system. 
     At this point all surface equipment is miming 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 of the Swellable packers have had time to swell. 
     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 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. 
     The same pressure  52  used to set the packers  117 ,  118 , and  119 , also reaches the Frac Module timer pressure devices  122 ,  121 , and  120 . In this case, all of the timers have been set to actuate close to the exact same time so when the tubing pressure reaches 1,500 psi, for example, all the devices  122 ,  121 , and  120  start counting time. If the lowermost zone  113  is to be stimulated first, the timer in device  120  may have been set at 30 minutes, i.e., the amount of time before the first sliding sleeve  123  is opened and the flapper in the closed position. The timer is zone  112  may be been set for 2 hours and the timer in zone  111 , may have been set for 3 hours. 
     At this point in time, possibly 15 minutes after initial setting pressure was applied, all of the packers are set and all of the timers are running. It is now critical to begin pumping the job since the timer clocks are ticking, unless the stand-down mode is to be utilized. The first zone  113  will need to be traced but the sliding sleeve  123  in Frac Module  108  must first open. The following paragraphs will explain how the sliding sleeve  123  opens. 
     Referring to  FIGS. 2 and 3 , pressure in area  52  enters port  21  and chamber  22  and acts on piston  25 . Piston  25  and solid height compressed spring  29  pushes on orifice piston  33 . As piston  25  face  26  moves to shoulder  27 , shear screws  31  shear against groove  100 . The shear screws  31  may be set to shear at 1,500 psi applied to piston  25 . The force in spring  29  has sufficient force to move orifice piston  33  downward against the fluid in chamber  39 . The fluid in chamber  39  must be forced through Lee Visco Jet  32 . The Visco Jet has a Lohm rating that allows fluid to travel through the jet at a specified rate with a specified fluid, such as silicone oil, 200 cs. The specified flow rate of the fluid, the load of spring  29 , and the total volume of fluid in chamber  39 , controls the velocity and time in which the orifice piston moves toward rod  38 . The variables of spring load, Jet Lohm rating, fluid type, and total fluid volume can be adjusted ahead of time to achieve a 30 minute time dwell until face  36 , of orifice piston  33  contacts face  37  of the rod  38 . 
     The spring  29  has sufficient load and stroke to move rod  38  downward through charged nitrogen chamber  45 . When the rod undercuts  102  of rod  38  move downward and seals  41  move out of seal bores  46 , nitrogen gas is allowed to exit chamber  45  and enter chamber  44 , hole  54 , and hole  57 . The gas pressure is of sufficient magnitude so when it acts on sliding sleeve piston  76 , the sliding sleeve  71  is shifted downward to open up frac port  70 . Frac port  70  then allows fluid communication form area  103  to area  104 . 
     Simultaneously, flapper  65  is pulled downward away from finger  64 , and flapper  65  rotates around axle  66 , and is biased to the closed position by spring  67  to form a seal on top of sliding sleeve  71 . Once the sliding sleeve  71  is fully shifted downward, excess nitrogen gas is allowed to escape through port  78  in order to equalize pressure around the sliding sleeve  71 . This is important in case the sliding sleeve  71  needs to be shifted closed by mechanical shifting tools, at a later point in time after the well has been treated. The seals  23  and  24  on piston  25  provide a seal to prevent communication of fluid backward from port  78  to port  21  or vice versa. In this case, once the sliding sleeve  71  is fully shifted down, the collets  89  lock in groove  90  to hold the sliding sleeve in the open position. Likewise, when the sliding sleeve  71  is closed, collets  88  lock in groove  87  to hold the sliding sleeve  71  in the closed position. 
     At this point in time, the sliding sleeve  123  is shifted open and the flapper  65  is sealing the top of the sliding sleeve  71  so when pumping fluid from the surface of the well, fluid will not pass through the inside of sliding sleeve  71 , but will be blocked by the flapper  65  and directed through frac Port  70  and into formation  113 . 
     Formation  113  is treated by pumping fluid, or slurry, down work string  115 , through the upper Frac Modules  106  and  107  and out of ports  70  located in Frac Module  108 , and thru perforations  113  and into formation  113 . This operation has been planned by the pumping company to be complete before the 2 hour time period programmed in Frac Module  107 . Of course the 2 hour time period could have been reduced to minimize the time between treating zones. 
     After 2 hours from the original initiation point of setting the packers and starting the timers, the sliding sleeve  71  in Frac Module  107  opens and flapper  65  closes per the above described process, so zone  112  can now be treated. 
     This process continues for all zones that are in the completion and stimulation program for the well. As each zone is treated up the well, each Frac Module operates independently from the others, so failure of one to operate does not affect the operation of the others. 
     Once all zones are treated, the surface stimulation equipment can move off location. Flow from the formations can be used to attempt to clean up the well. The flow will open the flappers and allow fluid to move up hole. 
     It is also common practice to go back in the well, wash out excess proppant, if proppant was used, break the frangible flapper disc&#39;s, and close sliding sleeve  71  for zone isolation, if desired. The sliding sleeves have profiles machined in the inside of the sleeves so that standard type mechanical shifting tools can be used to either open or close the ports  70 . 
     Referring to  FIG. 6 , where the “Stand-Down-Mode” feature has been added to the timing/pressure device along with an actuation piston, and a different means to provide energy to shift the sliding sleeve. In operation, before running the system into the well, all Frac Module timers have been preprogrammed to run a selected period of time. Typically the lowermost timer will be set to open a sleeve first, the second sleeve 30 minutes later, and the third sleeve 60 minutes later and so on up the tool string. Also, based on planned well pressure at the tools the “Stand-Down-Mode” Controllers are set to either the threshold pressure or the pressure pulse sequence. When all of the frac Modules are positioned in the well and it is time to begin the frac operation, tubing pressure  52  is applied from the surface of the well. All of the Frac Modules see the same tubing pressure  52  at the same time. Pressure  52  enters at port  139 . All Frac Module pistons  143  have been set to shear screws  145  at the same pressure. This pressure is calculated based on the area of piston  143 , i.e., area at seal  144  minus the area of seal  141  and the total shear value of the screws  145 . For example, all the pistons  143  will be set to open when 1500 PSI is applied to port  139  from the surface. 2000 PSI may be applied to be certain that all pistons have shifted. The pistons  143  will shift upward when pressure  52  acts on seals  141  and  144  and since pressure at location  140  is less, a resulting force upward will shear the screws  145  as the pistons move upward. Well pressure from location  140  or  52  has not entered into holes  178  since seals  142  and  144  have isolated holes  178 . Although, as pistons  143  move upward, seals  144  move up bores  171  until holes  178  are exposed to well pressure  52 . At this time well pressure  52  enters holes  178  and enters chambers  151  and into pressure transducers  152 . The pressure simultaneously enters all Frac Module Pressure Transducers at once, therefore, activating switch  154  which in turn starts all timers  156 . Simultaneously, pressure is acting on pressure transducer  164  and controllers  165  will tell switches  166  to allow the timers  156  to keep running as long as tubing pressure  52  is maintained from the surface at a pre-selected level. The timers  156  will typically activate the lower-most Frac Module first. In this module, the timer  156  will turn on switch  157  to connect battery power  158  to piercing device  159 . Piercing device  159 / 161  will produce a hole in membrane  162 . Pre-charged gas pressure in chamber  45  will escape into chamber  174 , through gap  47 , into chamber  44 , into hole  54 , into chamber  55 , into hole  57  and act on piston  76  ( FIG. 3 ) to shift sliding sleeve  71  to open frac port  70  and release the flapper  65  from the open position to the closed position. With the first Flapper closed and the first sleeve open, the first zone can be Fraced. During the Fracing operation, if surface pumping ever stops for any reason and the pressure  52  drops to a pre-programs threshold pressure, the controllers  165 , will cause all Frac Module switches  166  to open the battery power circuits in wires  163  to stop all timers  156 . The timers  156  are the type that if power is lost, the timer will remember the time it ran before power was lost. When surface pumping resumes, pressure  52  increases above the pre-programmed threshold and controller  165  then closes the circuit in wires  163 , and all timers resume operating where they left off. Once the first zone is Fraced, the timer in the next zone up the well will open the next sliding sleeve. As long as pumping continues, the zones up the well can be continuously Fraced until all zones are treated. If there are pumping delays, the timers will go into the “Stand-Down-Mode” until pumping resumes. 
     Referring to  FIG. 7 , the “Stand-Down-Mode” feature has been added to the timing/pressure device described in  FIG. 5 . This figure shows the controller  167  integrated into the pressure transducer  130  and switch  131  devices. The system will work similar to the  FIG. 4  operation but will include the “Stand-Down-Mode” as described in the  FIG. 6  operation described above. Overall, this option can provide a more compact timing unit. 
     Referring to  FIG. 8 , the completion hook-up has been simplified by eliminating isolation packers  117 ,  118 , and  119  from the Frac Modules. Also, the Sump packer  109  and locator  110  are not shown. The Packers are not needed since the completion is cemented in open hole  175 . The cement  176  seals completely around the Frac Modules. Sliding sleeve  123  is opened first and surface pump pressure is used to break through the cement and initiate a fracture in the producing formation. As the timers progressively open each sliding sleeve closes a flapper and each respective zone is broken down and traced. 
     Although the present invention has been described with respect to specific details, it is not intended that such details should be regarded as limitations on the scope of the invention, except to the extent that they are included in the accompanying claims.