OA12171A

OA12171A - Method and apparatus for stimulation of multiple formation intervals.

Info

Publication number: OA12171A
Application number: OA1200200231A
Authority: OA
Inventors: Randy C Tolman; Lawrence O Carlson; David A Kinison; Kris J Nygaard; Glenn S Goss; William A Sorem; Lee L Shafer
Original assignee: Exxonmobil Upstream Res Co
Priority date: 2000-02-15
Filing date: 2001-02-14
Publication date: 2006-05-08
Also published as: NO20023571D0; EP1264075B1; NZ520310A; MXPA02007728A; CA2397460A1; EA200200857A1; PE20011019A1; RO121145B1; BR0108418A; NO20023571L; CN1416499A; DK2282002T3; CN1281846C; WO2001061146B1; WO2001061146A1; AU2001236978B2; EP2282002A2; CA2397460C; EP1264075A4; AU3697801A

Abstract

The invention provides an apparatus and method for perforating and treating multiple intervals of one or more subterranean formations (86) intersected by a wellbore by deploying a bottom-hole assembly having a perforating device (134) and at least one sealing mechanism (120) within said wellbore. The perforating device (134) is used to perforate the first interval to be treated. Then the bottom-hole assembly is positioned within the wellbore such that the sealing mechanism (120), when actuated, establishes a hydraulic seal in the wellbore to positively force fluid to enter the perforations (230, 231) corresponding to the first interval to be treated. A treating fluid is then pumped down the wellbore and into the perforations (230, 231) created in the perforated interval. The sealing mechanism (120) is released, and the steps are then repeated for as many intervals as desired, without removing the bottom hole assembly from said wellbore.

Description

-1- 012171

METHOD AND APPARATUS FOR STIMULATION OF MULTIPLEFORMATION INTERVALS

FIELD OF THE INVENTION

This invention relates generally to the field of perforating and treatingsubterranean formations to increase the production of oil and gas therefrom. Morespecifically, the invention provides an apparatus and a method for perforating andtreating multiple intervals without the necessity of removing equipment from thewellbore between steps or stages.

BACKGROUND OF THE INVENTION

When a hydrocarbon-bearing, subterranean réservoir formation does not hâveenough penneability or flow capacity for the hydrocarbons to flow to the surface inéconomie quantifies or at optimum rates, hydraulic fracturing or Chemical(usually acid) stimulation is often used to increase the flow capacity. A wellborepenetrating a subterranean formation typically consists of a métal pipe (casing)cemented into the original drill hole. Holes (perforations) are placed to penetratethrough the casing and the cernent sheath surrounding the casing to allow hydrocarbonflow into the wellbore and, if necessary, to allow treatment fluids to flow from thewellbore into the formation.

Hydraulic fracturing consists of injecting fluids (usually viscous shearthinning, non-Newtonian gels or émulsions) into a formation at such high pressuresand rates that the réservoir rock fails and forms a plane, typically vertical, fracture(or fracture network) much like the fracture that extends through a wooden log as awedge is diiven into it. Granular proppant material, such as sand, ceramic beads, orother materials, is generally injected with the later portion of the fracturing fLuid tohold the fracture(s) open after the pressure is released. Increased flow capacity fromthe réservoir results from the easier flow path left between grains of the proppantmaterial within the fracture(s). In Chemical stimulation treatments, flow capacity isimproved by dissolving materials in the formation or otherwise changing formationproperties. -2- 012171

Application of hydraulic fractining as described above is a routine part ofPetroleum industry operations as applied to individual target zones of up to about 60meters (200 feet) of gross, vertical thickness of subteiranean formation. When thereare multiple or layered réservoirs to be hydraulically fractured, or a very thickhydrocarbon-bearing formation (over about 60 meters), then altemate treatmenttechniques are required to obtain treatment of tire entire target zone. The methods forimproving treatment coverage are commonly known as “diversion” methods inPetroleum industry teiminology.

When multiple hydrocarbon-bearing zones are stimulated by hydraulicfractining or Chemical stimulation treatments, économie and technicaî gains arerealized by injecting multiple treatment stages that can be diverted (or separated) byvarious means, including mechanical devices such as bridge plugs, packers, downholevalves, sliding sleeves, and baffle/plug combinations; bail sealers; particulates such assand, ceramic material, proppant, sait, waxes, resins, or other compounds; or byalternative fluid Systems such as vïseosified fluids, gelled fluids, foams, or otherchemically formulated fluids; or using limited entry methods. These and ail othermethods and devices for temporarily blocking the flow of fluids into or out of a givenset of perforations will be referred to herein as "diversion agents."

In mechanical bridge plug diversion, for example, the deepest interval is firstperforated and fracture stimulated, then the interval is typically isolated by awireline-set bridge plug, and the process is repeated in the next' interval up. Assumingten target perforation intervals, treating 300 meters (1,000 feet) of formation in thismanner would typically require ten jobs over a time interval of ten days to two weekswith not only multiple fracture treatments, but also multiple perforating and bridgeplug running operations. At the end of the treatment process, a weflbore clean-outoperation would be required to remove the bridge plugs and put the well onproduction. .The major advantage of using bridge plugs or other mechanical diversionagents is high confidence that the entire target zone is treated. The majordisadvantages are the high cost of treatment resulting from multiple trips into and outof the wellbore and the risk of complications resulting from so many operations in thewell. For example, a bridge plug can become stuck in the casing and need to be 012171 drilleâ out at great expense. A further disadvantage is that the required wellboreclean-out operation may damage some of the successfully fractured intervals. ' One alternative to nsing bridge plugs is filling the portion of wellboreassociated with the just fractured interval with fracturmg sand, commonly refeired to 5 as the Pine Island technique. The sand column in the wellbore essentially plugs offthe already fractured interval and allows the next interval to be perforated andfractured independently. The primary advantage is élimination of the problems andrisks associated with bridge plugs. The disadvantages are that the sand plug does notgive a perfect hydrauîic seal and it can be difScult to remove from the wellbore at the 10 end of ail the fracture stimulations. Unless the well’s fluid production is strongenough to carry the sand from the wellbore, the well may still need to be cleaned outwith a work-over rig or coiled tubing unit. As before, additional wellbore operationsincrease costs, mechanical risks, and risks of damage to the fractured intervals.

Another method of diversion involves the use of particulate materials, granular 15 solids that are placed in the treating fluid to aid diversion. As the fluid is pumped, andthe particnlates enter the perforations, a temporary block forms in the zone acceptingthe fluid if a suflâciently high concentration of particulates is deployed in the flowstream. The flow restriction then diverts fluid to the other zones. Afrer the treatment,the particulate is removed bÿ produced formation fluids or by injected wash fluid, 20 either by fluid transport or by dissolution. Commonly available particulate divertermaterials include benzoic acid, napthalene, rock sait (sodium chloride), resinmaterials, waxes, and polymers. Altematively, sand, proppant, and ceramic materials,could be used as particulate diverters. Other specialty particulates can be designed toprecipitate and form during the treatment. 25 Another method for diverting involves using viscosified fluids, viseous gels, or foams as diverting agents. This method involves pumping the diverting fluidacross and/or into the perforated interval. These fluid Systems are fonnulated totemporarily obstruci flow to the perforations due to viscosity or formation relativepermeability decreases; and are also designed so that at the desired time, the fluid 30 System breaks down, dégradés, or dissolves (with or without adding Chemicals orother additives to trigger such hreakdown or dissolution) such that flow can be -4- 012171 restored to or from the perforations. These fluid Systems can be used for diversion ofmatrix Chemical stimulation treatments and fracture treatments. Particulate divertersand/or bail sealers are sometimes incorporated into these fluid Systems in efforts toenliance diversion.

Another possible process is limited entry diversion in which the entire targetzone of the formation to be treated is perforated with a very small number ofperforations, generally of small diameter, so that the pressure loss across thoseperforations during pumping promûtes a high, internai wellbore pressure. Theinternai wellbore pressure is designed to be high enough to cause ail of the perforatedintervals to fracture simultaneously. If the pressure were too low, only the weakestportions of the formation would fracture. The primary advantage of limited entrydiversion is that there are no inside-the-casing obstructions like bridge plugs or sandto cause problems later. The disadvantage is that limited entry fracturing often doesnot work well for thick intervals because the resulting fracture is frequently toonarrow (the proppant cannot ail be pumped away into the narrow fracture and remainsin the wellbore), and the initial, high wellbore pressure may not last As the sandmaterial is pumped, the perforation diameters are often quickly eroded to larger sizesthat reduce the internai wellbore'pressure. The net result can be that not ail of thetarget zone is stimulated. An additional concem is the potential for flow capacity intothe wellbore to be limited by the small number of perforations. S orne of the problems resulting from failure to stimulate the entire target zoneor using mechanical methods that require multiple wellbore operations and wellboreentries that pose greater risk and cost as described above may be alleviated by usinglimited, concentrated perforated intervals diverted by bail sealers. The zone to betreated could be divided into sub-zones with perforations at approximately the centerof each of those sub-zones, or sub-zones could be selected based on analysis of theformation to target desired fracture locations. The fracture stages would then bepumped with diversion by bail sealers at the end of each stage. Specifically, 300meters (1,000 feet) of gross formation might be divided into ten sub-zones of about 30meters (about 100 feet) each. At the center of each 30 meter (100 foot) sub-zone, tenperforations might be shot at a density of three shots per meter (one shot per foot) of -5- 012171 casing. A fracture stage would then be pumped with proppant-laden fluid followed byten or more bail sealers, at least one for each open perforation in a single perforationset or interval. The process would be repeated until ail of tbe perforation sets werefractured. Such a System is described in more detail in U.S. Patent No. 5,890,536,issued April 6,1999.

Historically, ail zones to be treated in a particular job that uses bail sealers asthe diversion agent havebeen perforated prior to pumping treatment fluids, and bailsealers hâve been employed to divert treatment fluids from zones already brokendown or otherwise taking the greatest flow of fluid to other zones taking less, or no,fluid prior to the release of bail sealers. Treatment and sealing theoretically proceededzone by zone depending on relative brealcdown pressures or permeabilities, butproblème were frequently encountered with baîls prematurely seating on one or moreof the open perforations outside the targeted interval and with two or more zonesbeing treated simultaneously. Furthennore, fhis technique présumés that eachperforation interval or sub-zone would break down and fracture at sufficientlydifferent pressure so that each stage of treatment would enter only one set ofperforations.

The primary advantages of hall seaîer diversion are low cost and low risk ofmechanical problems. Costs are low because the process can typically be completedin one continuons operation, usually during just a few hours of a single day. Only thebail sealers are left in the wellbore to either flow out with produced hydrocarbons ordrop to the bottom of the well in an area known as the rat (or junk) hole. The primarydisadvantage is the inabiîity to be certain that only one set of perforations will fractureat a time so that the correct number of bail sealers are dropped at the end of eachtreatment stage. In fact, optimal benefit of the process dépends on one fracture stageentering the formation through only one perforation set and ail other open perforationsremaining substantially unaffected during that stage of treatment Furtherdisadvantages are lack of certainty that ail of the perforated intervals will be treatedand of the order in which these intervals are treated while the job is in progress.When the order of zone treatment is not known or controlled, it is not possible toensure that each individual zone is treated or that an individual stimulation treatment -6- 012171 stage has been optimally designed for the targeted zone. In sonie instances, it may notbe possible to control the treatment such that individnal zones are treated with singletreatment stages.

To overcome some of the disadvantages that may occur during stimulationtreatments when multiple zones are perforated prior to pumping treatment fluids, analternative mechanical diversion method has been developed that involves the use of a ’coiled tubing stimulation System to sequentially stimulate multiple intervals withseparate treatment As with conventional bail sealer diversion, ail intervals to betreated are perforated prior to pumping the stimulation treatment. Then coiled tubingis run into the wellbore with a mechanical "straddle-packer-like" diversion toolattached to the end. This diversion tool, when properly placed and actuated across theperforations, allows hydraulic isolation to be achieved above and below the diversiontool. After the diversion tool is placed and actuated to isolate the deepest set ofperforations, stimulation fluid is pumped down the interior of the coiled tubing andexits flow ports placed in the diversion tool between the upper and lower sealingéléments. Upon completion of the first stage of treatment, the sealing élémentscontained on the diversion tool are deactivated or disengaged, and the coiled tubing ispulled upward to place the diversion tool across the second deepest set of perforationsand the process is continued until ail of the targeted intervals hâve been stimulated orthe process is aborted due to operational upsets.

This type of coiled tubing stimulation apparatus and method hâve been used tohydraulically fracture multiple zones in wells with depths up to about S,000 feet.However, various technical obstacles, including friction pressure losses, damage tosealing éléments, depth control, running speed, and potential érosion of coiled tubing,cuirently limit deployment in deeper wells.

Excess friction pressure is generated when pumping stimulation fluids,particularly proppant-laden and/or high viscosity fluids, at high rates through longerlengths of coiled tubing. Depending on the length and diameter of the coiled tubing,tire fluid viscosity, and the maximum allowable surface hardware working pressures,pump rates could be limited to just a few barrels per minute; which, depending on thecharacteristics of a spécifie subterranean formation, may not allow effective 012171 -7- placement of proppant during hydraulic fracture treatments or effective dissolution offormation materials during acid stimulation treatments

Erosion of the coiled tubing could also be a problem as proppant-laden fluid ispumped down the interior of the coiled tubing at high velocity, including the portionof the coiled tubing that remains wound on the surface reel. The érosion concems areexacerbated as the proppant-laden fluid impinges on the "continuons bend" associatedwith the portion of the coiled tubing placed on the surface reel.

Most seal éléments (e.g., “cup” seal technology) currently used in the coiledtubing stimulation operations described above could expérience sealing problems orseal failure in deeper wells as the seals are run past a large number of perforations atthe higher well températures associated with deeper wells. Since the seals run incontact with or at a minimal clearance from the pipe wall, rough interior pipe surfacesand/or perforation burrs can damage the sealing éléments. Seals currently available instraddle-packer-like diversion tools are also constructed from elastomers which maybe unable to withstand the higher températures often associated with deeper wells.

Running speed of the existing Systems with cup seals is generally on the orderof 15 to 30 feet-per-minute running downhole to 30 to 60 feet-per-minute cominguphole. For example, at the lower running speed, approximately.13 hours would berequired to reach a depth of 12,000 feet before beginning the stimulation. Givensafety issues surrounding nighttime operations, this slow running speed could resuit inmultiple days being required to complété a stimulation job. If any problems areencountered during the job, tripping in and out of the hole could be very costlybecause of the total operation rimes associated with the slow running speeds.

Depth control of the coiled tubing System and straddle-packer-like diversiontool also becomes more difficult as depth increases, such that placing the tool at thecorrect depth to successfully execute the stimulation operation may be difficult. Thisproblem is compounded by shooting the perforations before running the coiled tubingSystem in the hole. The perforating operation uses a different depth measurementdevice (usually a casing collar locator system) than is generally used in the coiledtubing system. -8- 012171

In addition, the coiled tubing method described above requires that ail of theperforations be placed in the wellbore in a separate perforating operation prior topumping the stimulation job. The presence of multiple perforation sets open abovethe diversion tool can cause operational difficulties. For example, if the proppantfracture from the entrent zone were to grow verticaîly and/or poor quality cernent isprésent behind pipe, the fracture could intersect the perforation sets above thediversion tool such that proppant could "dump" back into the wellbore on top of thediversion tool and prevent further tool movement Also, it could be difficult toexecute circulation operations if multiple perforation sets are open above the diversiontool. For example, if the circulation pressures exceed the breakdown pressuresassociated with the perforations open above the diversion tool, the circulation may notbe maintained with circulation fluid unintentionally lost to the formation. A similar type of stimulation operation may also be performed using jointedtubing and a workover rig rather than a coiled tubing System. Using a diversion tooldeployed on jointed tubing may allow for larger diameter tubing to reduce frictionpressure losses and allow for increased pump rates. Also, concems over érosion andtubing' integrity may be reduced when compared to coiled tubing since heavier wallthickness jointed tubing pipe may be used and jointed tubing would not be exposed toplastic deformation when run in the wellbore. However, using this approach wouldlikely increase the time and cost associated with the operations because of slower piperunning speeds than those possible with coiled tubing.

To overcome some of the limitations associated with completion operationsthat require multiple bips of hardware into and out of the wellbore to perforate andstimulate subterranean formations, methods hâve been proposed for “single-bip”deployment of a downhole tool string to allow for fracture stimulation of zones inconjunction with perforating. Specifrcally, these methods propose operations thatmay minimize the number of required wellbore operations and time required tocomplété these operations, thereby reducing the stimulation beatment cost. Theseproposais include 1) having a sand slurry in the wellbore while perforating withoverbalanced pressure, 2) dumping sand from a bailer simultaneously with firing theperforating charges, and 3) including sand in a separate explosively released -9- 012171 container. These proposais ail allow for only minimal fracture pénétrationsurrounding the wellbore and are not adaptable to tbe needs of multi-stage hydraulicfracturing as described herein.

Accordingly, there is a need for an improved method and apparatus for5 individnally treating each of multiple intervals of a subterranean formation penetrated by a'wellbore while maintaining the économie benefîts of multi-stage treatment.There is also a need for a method and apparatus that can economically reduce the risksinhérent in the currently available stimulation treatment options for hydrocarbon-bearing formations with multiple or layered réservoirs or with thickness exceeding 10 about 60 meters (200 feet) while ensuring that optimal treatment placement isperformed with a mechanical diversion agent that positively directs treatment stagesto the desired location.

SUMMARY OF THE INVENTION

This invention provides an apparatus and method for perforating and treating 15 multiple intervals of one or more subterranean formations intersected by a wellbore.

The apparatus consists of a deployment means (e.g., coiled tubing, jointed tubing, electric line, wireline, downhole tractor, etc.) with a bottomhole assembly("BHA") comprised of at least a perforating device and a re-settable mechanicalsealing mechanism that may be independently actuated via one or more signaling 20 means (e.g., electronic signais transmitted via wireline; hydraulic signais transmittedvia tubing, annulus, umbilicals; tension or compression loads; radio transmission;fîber-optic transmission; on-board BHA computer Systems, etc.).

The method includes the steps of deploying the BHA within the wellboreusing a deployment means where the deployment means may be a tubing-string, 25 cable, or downhole tractor. The perforating device is positioned adjacent to theinterval to be perforated and is used to peiforate the interval. The BHA is positionedwithin the wellbore using the deployment means, and the sealing mechanism isactuated so as to establish a hydraulic seal that positively directs fluid pumped downthe wellbore to enter the perforated interval. The sealing mechanism is released. The 30 process can then be repeated, without removing the BHA from the wellbore, for atleast one additional interval of the one or more subterranean formations. -10- 012171

The deployment means can be a tubing string, including a coiled tubing orstandard jointed tubing, a wireline, a slickline, or a cable. Rafher than tubing or cabledeployment, the deployment means could also be a tractor System attached to theBHA. The tractor System may be a self-propelled, computer-controlled, and canyon-board signaling Systems such that it is not necessary to attàch cable or tubing tocontrol and actuate the BHA and/or tractor System. Altematively, the tractor Systemcould be controlled and energized by cable or tubing umbilicals such the tractorSystem and BHA are controlled and actuated via signais transmitted dowrihole usingthe umbilicals. Many different embodiments to the invention can exist depending onthe suspension means and spécifie components of the BHA. in the first embodiment of the invention, when the deployment means is atubing string, once an interval has been perforated the BHA can be moved and thesealing mechanism actuated to establish a hydraulic seal below the perforated interval.Then treating fluid can be pumped down the annulus between the tubing string and thewellbore and into the perforated interval. And a second treating fluid, such asnitrogen, could also be pumped down the tubing string at the same time that the firsttreating fluid is pumped down the annulus between the tubing string and the wellbore.

In the second embodiment, when the suspension means is a tubing string, oncean interval fias been perforated the BHA can be moved and the sealing mechanismactuated to establish a hydraulic seal above the perforated interval. Then treating fluidcan be pumped down the tubing string and into the perforated interval.

In the thixd embodiment, when the deployment means is a tubing string, theBHA can be moved and the sealing mechanism actuated to establish a hydraulic sealabove and below the perforated interval (where the sealing mechanism consiste of twoseal éléments spaced sufScient distance apart to straddle the perforated interval). Inthis third embodiment, treating fluid can be pumped down the tubing string itself,through a flow port placed in-between the two seal éléments of the sealing mechanismand into the perforated interval.

In a fourth embodiment of the invention, when the BHA is deployed in thewellbore using a wireline, slickline or cable, the BHA would be moved and thesealing mechanism actuated to establish a hydraulic seal below the perforated interval -11- 012171 to be treated, and the treating fluid would be pumped down the annulus between thewireline, slickline, or cable, and the weilbore.

In a fifih embodiment of die invention, an "umbilical” is deployed as anadditional means to actuate a BHA component. In the most general sense, theumbilical could take the form of a small diameter tubing or multiple tubing to providehydraulic communication with BHA. components; and/or the umbilical could take thefoim of a cable or multiple cables to provide electrical or electro-opticalcommunication with BHA components.

In a sixth embodiment of the invention, when the depioyment means is atractor System attached to the BHA, the BHA can be moved and the sealingmechanism actuated to establish a hydraulic seal below the perforated interval. Thetreating fluid can be pumped down the weilbore and into the perforated interval.

In a seventh embodiment of the invention, abrasive fluid-jet cuttingtechnology is used for perforating and the BHA is suspended by tubing such that theBHA eau be moved and the sealing mechanism actuated to establish a hydraulic sealbelow the perforated interval. The treating fluid would then be pumped down theannulus between the tubing and weilbore.

One of the primary advantages of this apparatus and method is that the BHA,including the sealing mechanism and the perforating device, does not need to beremoved from the weilbore prior to treatment with the treating fluid and betweentreatment of multiple formation zones or intervals. Another primary advantage of thisapparatus and method is that each treatment stage is diverted using a mechanicaldiversion agent such that précisé control of the treatment diversion process is achievedand each zone can be optimally stimulated. As a resuit, there are significant costssavings associated with réduction in the time required to perforate and treat multipleintervals within a weilbore. In addition, there are production improvementsassociated with using a mechanical diversion agent to provide precisely-controlledtreatment diversion when stimulating multiple formation interval within a weilbore.As such, the inventive method and apparatus provide significant économie advantagesover existing methods and equipment since the inventive method and apparatus allowfor perforating and stimulating multiple zones with a single weilbore entry, and -12- 012171 subséquent withdrawal, of a bottomhole assembly that provides dual fimctionality asboth amechanical diversion agent andperforating device.

BRIEF DESCRIPTION OF THE DRAWINGS

The présent invention and its advantages will be better understood by refeningto the following detailed description and the attached drawings in which:

Figure 1 illustrâtes one possible représentative wellbore configuration withperipheral equipment that could be used to support, the bottomhole assembly used inthe présent invention. Figure 1 also illustrâtes représentative bottomhole assemblystorage welîbores with surface slips that may be used for storage of spare orcontingency bottomhole assemblies.

Figure 2A illustrâtes the first embodiment of the bottomhole assemblydeployed using coiled tubing in an unperforated wellbore and positioned at the depthlocation to be perforated by the first set of selectively-fired perforating charges.Figure 2A further illustrâtes that the bottomhole assembly consists of a perforatingdevice, an inflatable, re-settable packer, a re-settable axial slip device, and ancillarycomponents.

Figure 2B represents the bottomhole assembly, coiled tubing, and wellbore ofFigure 2A after the first set of selectively-fired perforating charges are fired resultingin perforation holes through the production casing and cernent sheath and into the firstformation zone such that hydraulic communication is established between thewellbore and the first formation zone.

Figure 2C represents the bottomhole assembly, coiled tubing, and wellbore ofFigure 2B afier the bottomhole assembly has been re-positioned and the firstformation zone stimulated with the first stage of the multiple-stage, hydraulic,proppant fracture treatment where the first stage of the fracture treatment was pumpeddowhhole in the wellbore annulus existing between the coiled tubing and productioncasing. In Figure 2C, the sealing mechanism is shown in a de-activated positionsince, for illustration purposes only, it is assumed that no other perforations besidesthose associated with the first zone are présent, and as such, isolation is not necessaiyfor treatment of the first zone. -13- 012171

Figure 3A représente thê bottomhole assembly, coiled tubing, and wellbore ofFigure 2C after the bottomhole assembly has beenre-positioned and the second set ofselectively-fired perforating charges hâve been fired resulting in perforation hoîesthrongh the production casing and cernent sheath and into the second formation zonesnch that hydraulic communication is established between the wellbore and thesecond formation zone.

Figure 3B représente the bottomhole assembly, coiled tubing, and wellbore ofFigure 3A after the bottomhole assembly has been re-positioned a sufficient distancebelow the deepest perforation of the second perforation set to allow slight movementupward of the BHA to set the re-settable axial slip device while keeping the locationof the circulation port below the bottom-most perforation of the second perforationset

Figure 3C représente the bottomhole assembly, coiled tubing and wellbore ofFigure 3B after the re-settable mechanical slip device has been actuated to providerésistance to downward axial movement ensuring that the inflatàble, re-settable packerand re-settable mechanical slip device are located between the first zone and secondzone perforations.

Figure 3D représente the bottomhole assembly, coiled tubing and wellbore ofFigure 3C after the inflatable, re-settable packer has been actuated to provide a barrierto flow between the portion of the wellbore directly above the inflatable, re-settablepacker and the portion of the wellbore directly below the inflatable, re-settable packer.

Figure 3E représente the bottomhole assembly, coiled tubing, and wellbore ofFigure 3D after the second formation zone has been stimulated with the second stageof the multiple stage hydraulic proppant fracture treatment where the second stage ofthe fracture treatment was pumped downhole in the wellbore annulns existingbetween the coiled tubing and production casing.

Figure 3F représente the bottomhole assembly, coiled tubing, and wellbore ofFigure 3E after the inflatable, re-settable packer has been de-activated therebyre-establishing pressure communication between the portion of the wellbore directlyabove the inflatable, re-settable packer and the portion of the wellbore directly belowthe inflatable, re-settable packer. The re-settable mechanical slip device is stiU -14- 012171 energized and continues to prevent movement of the coiled tubing and bottomholeassembly down the wellbore.

Figure 4A represents a modified bottomhole assembly, similar to thebottomhole assembly described in Figures 2A through 2C and Figures 3Athrough 3F, but with the addition of a mechanical-plug, settable with a select-firecharge setting System, located below the string of perforating guns. Figure 4A alsorepresents the coiled tubing, and wellbore of Figure 3F after an additional, thirdperforating and fracture stimulation operation has been performed. In Figure 4A, it isnoted that only the second and third fractures and perforation sets are shown. IhFigure 4A, the modified bottomhole assembly is shown suspended by coiled tubingsuch that the location of the bridge-plug is located above the last perforated intervaland below the next interval· to be perforated.

Figure 4B represents the bottomhole assembly, coiled tubing, and wellbore ofFigure 4A after the mechanical-plug has been select-fire-charge-set in the well andafter the bottomhole assembly has been re-positioned and the first set ofselectively-fired perforating charges hâve been fired and resuit in perforation holesthrough the production casing and cernent sheath and into the fourth formation zonesuch that hydraulic communication is established between the wellbore and the fourthformation zone.

Figure 5 represents a second embodiment of the invention. In thisembodiment, the suspension means is a tubing string, and once an interval has beenperforated, the BHA can be moved and the sealing mechanism actuated to establish ahydraulic seal above the perforated interval. Then treating fluid can be pumped downthe tubing string and into the perforated interval.

Figure 6 represents a third embodiment of the invention. The suspensionmeans is a tubing string, and the BHA can be moved and the sealing mechanismactuated to establish a hydraulic seal above and below the perforated interva] (wherethe sealing mechanism consists of two seal éléments spaced sufficient distance apartto straddle the perforated interval). In this third embodiment, treating fluid can bepumped down the tubing string itself, through a fiow port placed in-between the twoseal éléments of the sealing mechanism and into the perforated interval. -15- 012171

Figure 7 représente a fourth embodiment of the invention. The BHA issuspended in the wellbore using a wireline (or slickline or cable). The BHA would bemoved and the sealing mechanism actnated to establish a hydraulic seal below theperforated interval to be treated, and the treating fluid would be pumped down theannulus between the wireline, slickline, or cable, and the wellbore.

Figures 8A and 8B represent a fifih embodiment of the invention that utilizesan umbilical tubing, deployed interior to the tubing used as the deployment means, foractuation of the re-settable sealing mechanism.

Figure 9 représente a sixth embodiment of the invention that utilizes a tractor'System attached to the BHA such that BHA can be moved and the sealing mechanismactuated to establish a hydraulic seal below the perforated interval. The treating fluidcan be pumped down the wellbore and into the perforated interval.

Figure 10 représente a seventh embodiment of the invention that utilizesabrasive or erosive fluid-jet cutting technology for the perforating device. The BHAis suspended in the wellbore using jointed tubing and consiste of a mechanicalcompression-set, re-settable packer, an abrasive or erosive fluid jet perforating device,a mechanical casing-collar locator, and ancillary components. In this embodiment,perforations are created by pumping an abrasive fluid down the jointed tubing and outof a jetting tool located on the BHA such that a high-pressure high-speed abrasive orerosive fluid jet is created and used to penetrate the production casing andsuirounding cernent sheath to establish hydraulic communication with the desiredformation interval. After setting the re-settable packer below the zone to bestimulated, the stimulation treatment can then pumped down the annulus locatedbetween the tubing string and the production casing string.

DETA3LED DESCRIPTION OF THE INVENTION

The présent invention will be described in connection with its preferredembodiments. However, to the extent that the following description is spécifie to aparticular embodiment or a particular use of the invention, this is intended to beillustrative only, and is not to be construed as Iimiting the scope of the invention. Onthe contrary, the description is intended to cover ail alternatives, modifications, and 012171 -16- équivalents that are included within the spirit and scope of the invention, as definedby the appended daims.

The présent invention provides a new method, new System, and a newapparatus for perforating and stimulating multiple formation intervals, which allowseach single zone to be treated with an individual treatment stage while eliminating orminimizing the problems that are associated with existing coiled tubing or jointedtubing stimulation methods and hence providing significant économie and technicalbenefit over existing methods.

Specifically, the invention involves suspending a bottomhole assembly in thewellbore to individually and sequentially perforate and treat each of the desiredmultiple zones while pumping the multiple stages of the stimulation treatment and todeploy a mechanical re-settable sealing mechanism to provide controlled diversion ofeach individual treatment stage. For the proposes of this application, “wellbore” willbe understood to include below ground sealed components of the well and also ailsealed equipment above ground level, such as the wellhead, spool pièces, blowoutpreventers, and lubricator.

The new apparatus consists of a deployment means (e.g., coiled tubing, jointedtubing, electric line, wireline, tractor System, etc.) with a bottomhole assemblycomprised of at least a perforating device and a re-settable mechanical sealingmechanism that may be independently actuated from the surface via one or moresignaling means (e.g., electronic signais transmitted via wireline; hydraulic signaistransmitted via tubing, annulus, umbilicals; tension or compression loads; radiotransmission; fiber-optic transmission; etc.) and designed for the anticipated wellboreenvironment and loading conditions.

In the most general sense, the term "bottomhole assembly" is used to dénoté astring of components consisting of at least a perforating device and a re-settablesealing mechanism. Additional components including, but not limited to, fishingnecks, shear subs, wash tools, circulation port subs, flow port subs, pressureequalization port subs, température gauges, pressure gauges, wireline connection subs,re-settable mechanical slips, casing collar locators, centralizer subs and/or connectersubs may also be placed on the bottomhole assembly to facilitate other anticipated -17- 012171 auxiliaiy or ancillary operations and measurements that may be désirable during thestimulation treatment

In the most general sense, the re-settable mechanical sealing mechanismpeiforms the fonction of providing a "hydraulic seal", where hydraulic seal is definedas sufficient flow restriction or blockage such that fluid is forced to be directed to adifferent location than the location it would otherwise be directed to if the flowrestriction were not présent. Specifically, this broad définition for "hydraulic seal" ismeant to include a "perfect hydraulic seal" such that ail flow is directed to a locationdifferent from the location the flow would be directed to if the flow restriction werenot présent; and an "imperfect hydraulic seal" such that an appréciable portion of flowis directed to a location different from the location the flow would be directed to if theflow restriction were not présent. Although it would generally be préférable to use are-settable mechanical sealing that provides a perfect hydraulic seal to achieve optimalstimulation; a sealing mechanism that provides an imperfect hydraulic seal could beused and an économie treatment achieved even though the stimulation treatment maynot be pêrfectly diverted.

In the first preferred embodiment of the invention, coiled tubing is used as thedeployment means and the new method involves sequentially perforating and thenstimulating the individual zones from bottom to top of the completion interval, withthe stimulation fluid pumped down the annular space between the production casingand the coiled tubing. As discussed forther below, this embodiment of the newapparatus and method offer substantial improvements over existing coiled tubing andjointed tubing stimulation technology and are applicable over a wide range ofwellbore architectures and stimulation treatment designs.

Specifically, the first preferred embodiment of the new method and apparatusinvolves the deployment system, signaling means, bottomhoïe assembly, andoperations as described in detail below, where the varions components, theirorientation, and operational steps are chosen, for descriptive purposes only, tocorrespond to components and operations that could be used to accommodatehydraulic proppant fracture stimulation of multiple intervals. -18- 012171

In the first prefeired embodiment for a hydraulic proppant fracture stimulationtreatoent, the apparalus would consist of the BHA deployed in tbe wellbore by coiledtubing. The BHA would include a perforating device; re-settable mecbanical sealingmechanism; casing-collar-locator; circulation ports; and other ancillaiy components(as described in more detail below).

Furfheimore, in this frrst prefeired embodiment, the perforating device wouldconsist of a select-fîre perforating gun System (using shaped-charge perforatingcharges); and tbe re-settable mechanical sealing mechanism would consist of aninflatable, re-settable packer, a mechanical re-settable slip device to preventdownward axial movement of the bottomhole assembly when set; and pressureequalization ports located above and below the inflatable re-settable packer.

In addition, in this first preferred embodiment, a wireline would be placedinterior to the coiled tubing and used to provide a signaling means for actuation ofselect-fîre perforation charges and for transmission of electric signais associated withthe casing-collar-locator used for BHA depth measurement.

Refening now to Figure 1, an example of the type of surface equipment thatcould be utilized in the first preferred embodiment would be a rig up that used a verylong lubricator 2 with the coiled tubing injector head 4 suspended high. in the air bycrâne aim 6 attached to crâne base 8. The wellbore would typically comprise a lengthof a surface casing 78 partially or wholly within a cernent sheath 80 and a productioncasing 82 partially or wholly within a cernent sheath 84 where the interior wall of thewellbore is composed of the production casing 82. The depth of the wellbore wouldpreferably extend some. distance below the lowest interval to be stimulated toaccommodate the length of the bottomhole assembly that would be attached to the endof the coiled tubing 106. Coiled tubing 106 is inserted into the wellbore using thecoiled tubing injection head 4 and lubricator 2. Also installed to the lubricator 2 areblow-out-preventors 10 that could be remotely actuated in the event of operationalupsets. The crâne base 8, crâne arm 6, coiled tubing injection head 4, lubricator 2,blow-out-preventors 10 (and their associated ancillary control and/or actuationcomponents) are standard equipment components well known to those skilled in theart that will accommodate methods and procedures for safely installing a coiled tubing -19- 012171 bottomhole assembly in a well under pressure, and subsequently removing thecoiled-tubing bottomhole assembly from a well under pressure.

With readily-available existing equipment, the height to the top of the coiledtubing injection head 4 could be approximately 90 féet from ground level with the 5 "goose-neck" 12 (where the coil is bent over to go down vertically into the well)approaching approximately 105 feet above the ground. The crâne arm 6 and crânebase 8 would support the load of the injector head 4, the coiled tubing 106, and anyload requirements anticipated for potential fishing operations (janing and pulling).

In general, the lubricator 2 must be of length greater than the length of the10 bottomhole assembly to allow the bottomhole assembly to be safely deployed in awellbore under pressure. Depending on the overall length requirements and asdetermined prudent based on engineering design calculations for a spécifieapplication, to provide for stability of the coiled tubing injection head 4 andlubricator 2, guy-wires 14 could be attached at various locations on the coiled tubing • 15 injection head 4 and lubricator 2. The guy wires 14 would be firmly anchored to theground to prevent undue motion of the coiled tubing injection head 4 and lubricator 2such that the integrity of the surface components to hold pressure would not becompromised. Depending on the overall length requirements, alternative injectionhead/îubricator System suspension Systems (coiled tubing rigs or fit-for-purpose 20 completion/workover rigs) could also be used.

Also shown in Figure 1 are several different wellhead spool pièces which may be used for flow control and hydraulic isolation during rig-up operations, stimulationoperations, and rig-down operations. The crown valve 16 provides a device forisolating the portion of the wellbore above the crown valve 16 from the portion of the 25 wellbore below the crown valve 16. The upper master fracture valve 18 and lowermaster fracture valve 20 also provide valve Systems for isolation of wellbore pressuresabove and below their respective locations. Depending on site-specific practices andstimulation job design, it is possible that not ail of these isolation-type valves mayactually be required or used. 30 The side outlet injection valves 22 shown in Figure 1 provide a location for injection of stimulation fiuids into the wellbore. The piping from the surface pumps -20- 012171 and tanks used for injection of the stimulation fluids would be attached withappropriate fittings and/or couplings to the side outlet injection valves 22. Thestimulation fluids would then be pumped into the wellbore via this flow path. Withinstallation of other appropriate flow control equipment, fluid may also be producedfrom the wellbore using the side outlet injection valves 22. It is noted that the interiorof the coiled tubing 106 can also be used as a flow conduit for fluid injection into thewellbore.

The bottomhole assembly storage wellbores 24 shown in Figure 1 provide alocation for storage of spare or contingency bottom-hole assemblies 27, or for storageof bottomhole assemblies that hâve been used during previous operations. Thebottomhole assembly storage wellbores 24 may be drilled to a shallow depth such thata bottomhole assembly that may contain perforating charges may be safely held inplace with surface slips 26 such that the perforating charges are located below groundlevel unti.1 the bottomhole assembly is ready to be attached to the coiled tubing 106.The bottomhole assembly storage wellbores 24 may be drilled to accommodateplacement of either cemented or uncemented casing string, or may be left uncasedaltogether. The actual number of bottomhole assembly storage wellbores 24 requiredfor a particular operation would dépend on the overall job requirements. Thebottomhole assembly storage wellbores 24 could be located within the reach of thecrâne aim 6 to accommodate rapid change-out of bottomhole assemblies during thecourse of the stimulation operation without the necessity of physically relocating thecrâne base 8 to another location.

Refeiring nôw to Figure 2A, coiled tubing 106 is equipped with a coiledtubing connection 110 which may be connected to a shear-release/fishing neckcombination sub 112 that contains both a shear-release mechanism and a fishing neckand allows for the passage of pressurized fluids and wireline 102. The shear-release/fishing neck combination sub 112 may be connected to a sub containing acirculation port sub 114 that may provide a flow path to wash débris from above theinflatable, re-settable packer 120 or provide a flow path to inject fluid dowrihole usingthe coiled tubing 106. The circulation port sub 114 contains a valve assembly thatactuates the circulation port 114 and the upper equalization port 116. The upper 012171 -21 - equalization port 116 may be connected to a lower equalization port 122 via tubingthrough the inflatable, re-settable packer 120. Both the circulation port 114 and theupper equalization port 116 would preferabîy be open in the "ruuning position",thereby allowing pressure communication between the internai coiled-tubing pressureand the coiled tubing by casing annulus pressure. Within this document, "runningposition" refers to the situation where ail components in the bottomhole assemblypossess a configuration that pennits unhindered axial movement up and down thewellbore. The lower equalization port 122 located below the inflatable, re-settablepacker 120 is always open and flow through the equalization ports is controlled by theupper equalization port 116. The circulation and equalization ports can be closedsimultaneously by placing a slight compressive load on the BHA. To preventpotentiel back-flow into the coiled tubing when the circulation port 114 is open in therunning position, a surface pressure can be applied to the coiled tubing 106 such thatthe pressure inside the circulation port 114 exceeds the wellbore pressure directlyoutside the circulation port 114. The re-settable, inflatable packer 120 is hydraulicallyisolated fronr the internai coiled tubing pressure in the' running position. Theinflatable, re-settable packer 120 can gain pressure communication via internaivalving with the internai coiled tubing pressure by placing a slight compressive loadon the BHA. Mechanicaîly actuated, re-settable axial position locking devices, or"slips," 124 may be placed below the inflatable, re-settable packer 120 to resistmovement down the wellbore. The mechanical slips 124 may be actuated through a"continuons J" mechanism by cycling the axial load between compression andtension. A wireline connection sub 126 is located above the casing collai locator 128and select-fire perforating gun System. A gun connection sub 130 connects the casingcollar locator 128 to select-fire head 152. The perforating gun System may bedesigned based on knowledge of the number, location, and thickness of thehydrocarbon-bearing sands within the target zones. The gun System will be composedof one gun assembly (e.g., 134) for each zone to be treated. The first (lowest) gunassembly will consist of a select-fire head 132 and a gun encasement 134 which willbe loaded with perforating charges 136 and a select-fire detonating system. -22- 012171

Specifically, a prefeired embodiment of the new method involves thefollowing steps, where the stimulation job is chosen, for descriptive puiposes, to be amulti-stage, hydraulic, proppant-fracture stimulation. 1. The well is drilled and casing is cemented across the interval to be completed,and if desired, one or more bottomhole assembly storage wellbores are drilledand completed. 2. The target zones within the completion interval are identified (typically by acombination of open-hole and cased-hole logs). 3. The bottomhole assemblies (BHA), and perforating gun assemblies to bedeployed on each BHA anticipated to be used during the stimulationoperation, are designed based on knowledge of the number, location, andthickness of the hydrocarbon-bearing sands within the target zones. 4. A reel of coiled tubing is made-up with a preferred embodiment BHAdescribed above. The reel of coiled tubing would also be made-np to containthe wireline that is used to provide a signaling means for actuation of theperforating guns. Preferably, the desired quantity of appropriately configuredspare or contingency BHA’s would also be made-up and stored in thebottomhole assembly storage wellbore(s). The coiled tubing may bepre-loaded with fluid either before or after attaching the BHA to the coiledtubing. 5. As shown in Figure 1, the coiled tubing 106 with BHA is run into the well viaa lubricator 2 and the coiled tubing injection head 4 is suspended by crânearm 6. 6. The coiled tubing/BHA is run into the well while coirelating the depth of theBHA with the casing collar locator 128 (Figure 2A). 7. The coiled tubing/BHA is run below the bottom-most target zone to ensurethat there is sufficient wellbore depth below the bottom-most perforations tolocate the BHA below the first set of perforations during fracturing operations. -23- 012171

As shown in Figure 2A, the inflatable, re-settable packer 120 and re-settàblemechanically actuated slips 124 are in the running position. 8. As shown in Figure 2B, the coiled tubing/BHA is fhen raised to a locationwithin the wellbore such that the first (lowest) set of perforation charges 136contained on the first gun assembly 134 of the select-fire perforating gunSystem are located directly across the bottom-most target zone where précisédepth control may be established based on readings from thecasing-collar-locator 128 and coiled tubing odometer Systems (not shown).The action of moving the BHA up to the location of the first perforatedinterval will cycle the mechanical slip "continuons J" mechanism (not shown)into the pre-lock position where subséquent downward motion will force there-settable mechanical slip 124 into the locked position thereby preventingfurther downward movement. It is noted that additional cycling of the coiledtubing axial-load from compression to tension and back will retum the re-settable mechanical slips to running position. In this manner, the mechanicalslip continuons J mechanism coupled with the use of compression and tensionloads transmitted via the suspension means (coiled tubing) are used to providedowhhole actuation and de-actuation of the mechanical slips. 9. The first set of perforation charges 136 are selectively-fired by remoteactuation via wireline 102 communication with the first select-fire head 132 topenetrate the casing 82 and cernent sheath 84 and establish hydrauliccommunication with the formation 86 through the résultantperforations 230-231. It will be understood that any given set of perforationscan, if desired, be a set of one, although generally multiple perforations wouldprovide improved treatment results. It will also be understood that more thanone segment of the gun assembly may be fired if desired to achieve the targetnumber of perforations whether to remedy an actual or perceived misfire orsimply to increase the number of perforations. It will also be understood thatan interval is not necessarily limited to a single réservoir sand. Multiple sandintervals could be perforated and treated as a single stage using other diversion -24- 012171 agents suitable for simultaneous déployaient with this invention within a givenstage of treatment.

10. As shown in Figure 2C, the coiled tubing may be moved to position th.ecirculation port 114 directly below the deepest perforation 231 ôf this firsttarget zone to minimize potential for proppant fill above the inflatable,re-settable packer 120 and rninimize high velocity proppant flow past theBHA 11. The first stage of the fracture stimulation treatment is initiated by circulating asmall volume of fluid down the coiled tubing 106 through the circulationport 114 (via a positive displacement pump). This is followed by initiating thepumping of stimulation fluid down the annulus between the coiled tubing 106and production casing 82 at fracture stimulation rates. The small volume offluid fîowing down the coiled tubing 106 serves to keep a positive pressureinside the coiled tubing 106 to resist proppant-laden fluid backflow into thecoiled tubing 106 and to resist coiled tubing collapse loading during fracturingoperations. It is noted that as an alternative means to resist coiled tubingcollapse, an internai valve mechanism may be used to maintain the circulationport 114 in the closed position and with positive pressure then applied to thecoiled tubing 106 using a surface pump. As an illustrative example of thefracture treatment design for stimulation of a 15-acre size sand lens containinghydrocarbon gas, the frrst fracture stage could be comprised of "sub-stages" asfollows: (a) 5,000 gallons of 2% KC1 water; (b) 2,000 gallons of cross-lihkedgel containing 1 pound-per-gallon of proppant; (c) 3,000 gallons of cross-linked gel containing 2 pounds-per-gallon of proppant; (d) 5,000 gallons ofcross-linked gel containing 3 pounds-per-gallon of proppant; and (e) 3,000gallons of cross-linked gel containing 4 pound-per-gaîlon of proppant suchthat 35,000 pounds of proppant are placed into the first zone. 12. As shown in Figure 2C, ail sub-stages of the first fracture operation arecompleted with the création of the first proppant fracture 232. 012171 -25- 13. At the end of the first stage of the stimulation treatment, should proppant inthe wellbore prevent the coiled tubing/BHA from immédiate movement; fluidcan be circulated through the circulation port 114 to wash-over and clean-outthe proppant to free the coiled tubing/BHA and allow movement. 14. As shown in Figure 3A, the coiled tubing/BHA is then pulled uphole toslightly above the second deepest target zone such that the second set ofperforation charges 146 contained on the select-fîre perforating gunSystem 144 are located slightly above the second deepest target zone whereagain précisé depth control is established based on readings from thecasing-collar-locator 128 and coiled tubing odometer Systems. The action ofmoving the BHA upward (to slightly above the second interval to beperforated) will cycle the re-settable mechanical slip "continuons J"mechanism into the pre-lock position. Further cycling of compression/tensionloads are perfoimed to place the mechanical slip continuons J mechanism backinto the running position. The coiled tubing/BHA is then moved downward toposition the perforation charges 146 contained on the select-fire perforatinggun System 144 directly across from the second deepest target zone whereagain précisé depth control is established based on readings from thecasing-collar-locator 128 and coiled tubing odometer Systems. 15. The second set of perforation charges 146 are selectively-fired by remoteactuation via the second select-fîre head 142 to penetrate the casing 82 andcernent sheath 84 and establish hydraulic communication with theformation 86 through the résultant perforations 240-241. 16. As shown in Figure 3B, the coiled tubing may be moved down the wellbore toposition the BHA several feet below the deepest perforation 241 of the secondtarget zone. Subséquent movement of the BHA up the wellbore to position thecirculation port 114 directly below the deepest perforation 241 of this secondtarget zone will cycle the re-settable mechanical slips 124 into the pre-lockposition, where subséquent downward motion will force the re-settable -26- 012171 mechanical slips 124 into the locked position thereby preventing furtherdownward movement. 17. As shown in Figure 3C, downward movement engages the re-settablemechanical slips 124 with the casing wall 82 thereby preventing furtherdownward movement of the BHA. A compression load on the coiled tubing isthen applied and this load closes the circulation port 114 and upperequalization port 116, and créâtes pressure communication between theinflatable, re-settable packer 120 and the internai coiled tubing pressure. Thecompression load also locks the circulation port 114 into a position directlybelow the deepest perforation 241 of this second target zone (to minimizepotential for proppant fill above the inflatable, re-settable packer 120 andminimize high velocity proppant flow past the BHA) and with the re-settable,inflatable packer 120 positioned between the first and second perforatedintervals. 18. A further compression load is set down on the coiled tubing/BHA to test there-settable mechanical slips 124 and ensure that additional downward forcedoes not translate into further movement of the BHA down the wellbore. 19. As shown in Figure 3D, the inflatable, re-settable packer 120 is actuated bypressurizing the coiled tubing 106 to effect a hydraulic seal above and belowthe inflatable, re-settable packer 120. A compression load is maintained on theBHA to maintain pressure communication between the internai coiled tubingpressure and the inflatable, re-settable packer 120, to keep the circulationport 114 and the upper equalization port 116 closed, and to keep the re-settablemechanical slips 124 in the locked and energized position. The inflatable,re-settable packer 120 is maintained in the actuated State by maintainingpressure in the coiled tubing 106 via a surface pump System (it is noted thataltematively, the inflatable, re-settable packer could be maintained in anactuated State by locking pressure in to the element using an internai valveremotely controlled from surface by a signaling means compatible with otherBHA components and other présent signaling means). -27- 012171 20. The second stage of the fracture stimulation treatment is initiated with fluidpumped down the annulus between frie coiled tubing 106 and productioncasing 82 at fracture stimulation rates while maintaining compression load onthe BHA to keep the circulation port 114 and upper equalization port 116closed, and maintaining coiled tubing pressure at a sufficient level to resistcoiled tubing string collapse and to keep the inflatable, re-settable packer 120inflated and serve as a hydraulic seal between the annular pressure above frepacker before, during and after the fracture operation and the sealed wellborepressure below the inflatable, re-settable packer. 21. Ail sub-stages of fre fracture operation are pumped leaving a minimalunder-flush of the proppant-laden last sub-stage in fre wellbore so as not toover-displace fre fracture treatment If during the course of fris treatmentstage, the seal integrity of fre inflatable, re-settable packer 120 is believed tobe compromised, fre treatment stage could be temporarily suspended to testfre packer seal integrity above the highest (shaîlowest) existing perforations(e.g., perforation 240 in Figure 3D) after setting fre inflatable, re-settablepacker 120 in blank pipe. If fre seal integrity test were to be performed, itcould be désirable to perforai a circulation/washing operation to ensure anyproppant that may be présent in fre wellbore is circulated out of fre wellboreprior to conducting fre test The circulation/washing operation could beperformed by opening fre circulation port 114 and fren pumping of circulationfluid down the coiled tubing 106 to circulate fre proppant out of fre wellbore. 22. As shown in Figure 3E, ail sub-stages of fre second fracture operation arecompleted with fre création of a second proppant fracture 242. 23. After completing fre second stage fracture operation and ceasing injection ofstimulation fluid down fre annulus formed between fre coiled tubing 106 andproduction casing 82, a small tension load is applied to fre coiled tubing 106while maintaining internai coiled tubing pressure. The small applied tensionfirst isolâtes fre inflatable, re-settable packer pressure from fre coiled tubingpressure thereby locking pressure in fre inflatable, re-settable packer 120 and -28- 012171 theréby maintaining a positive pressure seal and imparting significantrésistance to axial movement of the inflatable, re-settable packer 120. In thesame motion, the applied tension may fhen open the circulation port 114 andequalization port 116 theréby allowing the coiled tubing pressure to bleed off 5 into the annulus fonned by the coiled tubing 106 and production casing 82 while simultaneously allowing the pressure above and below the inflatable,re-settable packer 120 to equilibrate. The surface System pump providinginternai coiled tubing pressure may be stopped after equilibrating thedownhole pressures. 10 24. After the pressures inside the coiled tubing, in the annulus foimed by the coiled tubing 106 and production casing 82 above the inflatable, re-settablepacker 120, and in the annulus fonned by the BHA and production casing 82below the inflatable, re-settable packer 120 equilibrate, a compressive loadplaced on the coiled tubing will close the circulation port 114 and upper 15 equalization port 116 before releasing the pressure trapped within the inflatable, re-settable packer 120 into the coiled tubing 106. This release ofinternai pressure from the inflatable, re-settable packer 120 will allow theinflatable, re-settable packer 120 to retract from the production casing wall, asshown in Figure 3F, in the absence of an extemal differential pressure across 20 the inflatable, re-settable packer 120 which could otherwise resuit in forces and movement that could damage the coiled tubing 106 or BHA. 25. Once the inflatable, re-settable packer 120 is unset, as shown in Figure 3F,tension pulled on the coiled tubing/BHA could de-energize the re-settablemechanical slips 124 thereby allowing the BHA to be free to move and be 25 repositioned up the wellbore. 26. If at the end of the second stage of the stimulation treatment, proppant in thewellbore prevents the coiled tubing/BHA from immédiate movement, fluidmay be circulated through the circulation port 114 to wash-over and clean-outthe proppant to free the coiled tubing/BHA and allow upward movement of the 30 BHA after releasing the inflatable, re-settable packer. -29- 012171 27. The process as described above is repeated until ail planned zones areindividually-stimulated (Figures 3À to 3F represent a BHA designed for athree zone stimulation). 28. Upon completion of the stimulation process, the components of the BHA areretumed to running position and the coiled tubingZBHA assembly is removedfrom the wellbore. 29. If ail the desired target zones hâve been stimulated, the well can beimmediately placed on production. 30. If it is désirable to stimulate additional zones, a reel of coiled tubing may bemade-up with a slightly modified BHA as shown in Figure4A. In tbisassembly, the only alteration to the BHA of the preferred embodimentdescribed above may be the addition of a select-fire-set mechanical plug 164or select-fîre set bridge-plug 164 located below the lowest select-fire gunassembly as shown in Figure 4A. In general, the select-fire-set mechanicalplug 164 can be either a bridge plug or a fracture baffle. A fracture bafflewould generally be preferred if it is désirable to simultaneously produce zonesseparated by the plug immediately after the stimulation job. 31. The modified BHA, shown in Figure 4A, consists of a select-fire perforatinggun System (Figure 4A depicts a gun System comprising perforating guns 174,184 and 194 with associated charges 176, 186 and 196 and select-fire heads172, 182 and 192), a casing-collar-locator 128, fiow ports 114, 116 and 122,an inflatable, re-settable packer 120, a re-settable mechanical axial slipdevice 124 and select-fire bridge plug 164 set using select-fire head 162. Themodified BHA is run into the well via a lubricator and the coiled tubinginjection head suspended by crâne or rig above the wellhead. 32. The coiled tubing/BHA is run into the well while correlating the depth withthe casing collar locator. 33. As shown in Figure 4A, the coiled tubing/modified BHA is run into thewellbore to position the select-fire mechanical-plug 164 above the lastpreviousîy stimulated zone 252. -30- 012171 34. As shown in Figure 4B the select-fire firing head 162 is fired to set theselect-fire mechanical plug 164 àbove the last previously stimulated zone 252. 35. After the bridge-plug select-fire head 162 is activated to set the select-firebridge-plug 164, the coiled tubing/modified BHA is then raised to a locationwithin the wellbore such that the first (lowest) set of perforation charges 176contained on the select-fire perforating gun System are located directly across"the next, bottom-most target zone to be perforated where précisé depth controlmay be established based on readings from the casing-collar-locator 128 andcoiled tubing odometer Systems located on the surface equipment. The actionof moving the BHA up to the location of the first perforated interval will cyclethe re-settable mechanical slips 124 into the locked position and will requirecycling the coiled tubing axial load fiom compression to tension and back toretum the re-settable mechanical slips to running position. 36. As shown in Figure 4B, the first set of perforation charges 176 on themodified BHA are selectively-fired by remote actuation via the secondselect-fire head 172 to penetrate the casing 82 and cernent sheath 84 withperforations 270, 271 and establish hydraulic communication with theformation 86 through the résultant perforations 270-271. 37. If there is insufficient space between the last previously placedperforations 250, 251 and the location of the next set of perforations 270, 271to be stimulated to enable appropriate placement of the BHA for perforation,isolation and stimulation of the next set of perforations 270, the select-firebridge plug 164 may be set below the last preyiously stimulatedperforations 250, 251, and the inflatable, re-settable packer may be employedduring the first stimulation operation to isolate the upper-mostperforations 270,271 fiom the previously stimulated perforations 250,251. 38. The entire process as described àbove is then repeated as appropriate until ailplanned zones are individually-stimulated (Figure 4A and Figure 4Brepresent a BHA designed for an additional three zone stimulation operation). -31- 012171

It will be recognized by those skilled in the art that the preferred suspensionmethod when proppant-laden fîuids are involved would be conventional jointedtubing or coiled tubing, preferably with one or more circulation ports so that proppantsettling in the wellbore could easily be circulated out of lhe wellbore. Treatmentssuch as acid fracturing or matrix acidizing may not require such à capability and couldreadily be performed with a deployment System based on cable such as slicküne orwireline, or based on a downhole tractor System.

It will be recognized by those skilled in the art that depending on theobjectives of a particular job, various pumping Systems could be used and couldinvolve the following arrangements: (a) pumping down the annulus created betweenthe cable or tubing (if the deployment method uses cable or tubing) and the casingwall; (b) pumping down the interior of the coiled tubing or jointed tubing if thesuspension method involves the use of coiled tubing or jointed tubing and excessfriction and proppant érosion were not of concem for the well depths considered; or (c) shnultaneously pumping down the annulus created between the tubing (if thedeployment method involves tubing) and the casing wall and 1he interior of the tubingif excess friction and proppant érosion were not of concem for the well depthsconsidered.

Figure 5 illustrâtes a second embodiment of the invention where coiled tubingis used as the deployment means and excess friction is not of concem and eitherproppant is not pumped during the job or use of proppant is not of concem. Figure 5shows that coiled tubing 106 is used to suspend the BHA and BHA components. Intins embodiment, the individual zones are treated in sequential order from shallowerwellbore locations to deeper wellbore locations. In this embodiment, as shown inFigure 5, circulation port 114 is now placed below the inflatable, re-settablepacker 120 such that treatment fluid may be pumped down the interior of coiledtubing 106, exit the circulation port 114, and be positively forced to enter the targetedperforations. As an illustration of the operations, Figure 5 shows that the inflatable,re-settable packer 120 has been actuated and set below perforations 241 that areassociated with a previous zone hydraulic fracture 242. The inflatable, re-settablepacker 120 provides hydraulic isolation such that when treatment fluid is subsequently -32- 012171 pumped down the coiled tubing 106, the treating fluid is forced to enter previouslyplaced perforations 230 and 231 and create new hydrauîic fractures 232. Theoperations are then continued and repeated as appropriate for the desired number offormation zones and intervals.

Figure 6 illustrâtes a third embodiment of the invention where coiled tubing isused as the deployment means and excess friction is not of concem and eitherproppant is not pumped during the job or use of proppant is not of concem. Figure 6shows that coiled tubing 106 is used to suspend the BHA and BHA components. Inthis embodiment, the individual zones may be treated in any order. In thisembodiment, as shown in Figure 6, a straddle-packer inflatable sealingmechanism 125 is used as the re-settable sealing mechanism and the circulation port114 is now placed between the upper inflatable sealing element 121 and the lowerinflatable sealing element 123. When the upper inflatable sealing element 121 and thelower inflatable sealing element 123 are actuated, treatment fluid may be pumpeddown the interior of coiled tubing 106 to exit the circulation port 114, and then bepositively forced to enter the targeted perforations. As 'an illustration of theoperations, Figure 6 shows that the upper inflatable sealing element 121 and thelower inflatable sealing element 123 hâve been actuated and set acrossperforations 241 that are associated with the next zone to be fractured. The inflatable,re-settable packer 120 provides hydrauîic isolation such that when treatment fluid issubsequently pumped down the coiled tubing 106, the treating fluid is forûed to enterpreviously placed perforations 240 and 241 and create new hydrauîic fractures 242.The operations are then continued and repeated as appropriate for the desired numberof formation zones and intervals.

Figure 7 illustrâtes a fourth embodiment of the invention where a wireline 102is used as the deployment means to suspend the BHA and BHA components. In thisembodiment, the individual zones are treated in sequential order from deeper wellborelocations to shallower wellbore locations. In this embodiment, as shown in Figure 7,treatment fluid may be pumped down the annulas between the wireline 102 andproduction casing wall 82 and be positively forced to enter the targeted perforations.In this embodiment, the inflatable re-settable packer 120 also contains an internai -33- 012171 electrical pump System 117, powered by electrical energy transmitted downhole viathe wireline, to inflate or deflate the inflatable, re-settable packer 120 using wellborefluid. Figure 7 shows that the inflatable, re-settable packer 120 has been actuated andset below the perforations 241 that are associated with the next zone to be fractured.The inflatàble, re-settàble packer 120 provides hydraulic isolation such that whentreatment fluid is subsequently pumped down the annulus between the wireline 102and production casing 82, the treating fluid is forced to enter perforations 240 and 241and create new hydraulic fractures 242. The operations are then continued andrepeated as appropriate for the desired nimber of formation zones and intervals. A fiflh embodiment of the invention involves deployment of additional tubingstrings or cables, hereinafter referred to as “umbilicals”, interior and/or exterior tocoiled tubing (or jointed tubing). As shown in Figure 8À and Figure 8B, a tubingumbilical 104 is shown deployed in the interior of the coiled tubing 106. In thisembodiment, the tubing umbilical 104 is connected to the re-settable sealingmechanism 120 and in this embodiment the re-settable sealing mechanism 120 is nowactuated via hydraulic pressure transmitted via the umbilical 104. In general, multipleumbilicals can be deployed either in the interior of the coiled tubing and/or in theannulus between the coiled tubing and production casing. ha general, the umbilicalscan be used to perform several different operations, including but not limited to,providing (a) hydraulic communication for actuation of individual BELA componentsincluding, but not limited to, the sealing mechanism and/or perforating device; (b)flow conduits for downhole injection or circulation of additional fluids; and (c) fordata acquisition from downhole measurement devices. It is noted that as shown inFigure 8A, the BHA also includes centralizers 201, 203, and 205 that are used to keepthe BEA centralized in the wellbore when BHA components are in the runningposition.

The use of an umbilical(s) can provide the ability to hydraulically engageand/or disengage the re-settable mechanical sealing mechanism independent of thehydraulic pressure condition wrthin the coiled tubing. This then allows the method tobe extended to use of re-settable mechanical sealing mechanisms requiringindependent hydraulic actuation for operation. Perforating devices that require -34- 012171 hydraulic pressure for selective-firing can be actuated via an umbilical. This may thenallow the wireline, if deployed with the coiled tubing and BEA, to be nsed fortransmission of an additional channel or channels of electrical signais, as may bedésirable for acquisition of data from measurement gauges located on the bottomholeassembly; or actuation of other BHA components, for example, an electricaldownhole motor-drive that could provide rotation/torque for BHA components.Altematively, an umbilical could be used to operate a hydraulic motor for actuation ofvarious downhole components (e.g., a hydraulic motor to engage or disengage the re-settable sealing mechanism).

The use of an umbilical(s) can provide the ability to inject or circulate anyfluid downhole to multiple locations as desired with précisé control. For example, tohelp mitigate proppànt settling on the sealing mechanism during a hydraulic proppantfracture treatment, umbilical(s) could be deployed and used to provide independentcontinuons or intermittent washing and circulation to keep proppant fromaccumulating on the sealing mechanism. For example, one umbilical could run to justabove the re-settable mechanical sealing mechanism while another is run just belowthe re-settable mechanical sealing mechanism. Then, as desired, fluid (e.g., nitrogen)could be circulated downhole to either or both locations to wash the proppant from therégion suirounding the sealing mechanism and hence mitigate the potential for theBHA sticking due to proppant accumulation. In the case of fluid circulation, it isnoted thaï the umbilical size and fluid would be selected to ensure the desired rate isachieved and is not unduly limited by friction pressure in the umbilical.

In addition to umbilicals comprised of tubing strings that provide hydrauliccommunication downhole as a signaling means for actuation of BHA components (orpossibly as a signal transmission means for surface recording of downhole gauges), ingeneral, one or more wireline or fiber-optic cables could be deployed in the wellboreto provide a electrical or electro-optical communication downhole as a signalingmeans for actuation of BHA components (or possibly as a signal transmission meansfor surface recording of downhole gauges).

Figure 9 illustrâtes a sixth embodiment of the invention where a tractorSystem, comprised of upper tractor drive unit 131 and lower tractor drive unit 133, is. -35- 012171 attached to the BHA and is ussd to deploy and position the BHA within the wellbore.In tins embodiment, the individual zones are treated in sequential order from deeperwellbore locations to shallower wellbore locations. In this embodiment, the BHA alsocontains an internai electrical pump System 117, powered by electrical energytransmitted downhole via the wireline 102, to inflate or deflate the inflatable,re-settable packer 120 using wellbore fluid. In this embodiment, treatment fluid ispumped down the annulus between the wireline 102 and production casing wall 82and is positively forced to enter the targeted perforations. Figure 9 shows thaï theinflatable, re-settable packer 120 has been actuated and set below the perforations 241that are associated with the next zone to be fractured. The inflatable, re-settablepacker 120 provides hydraulic isolation such that when treatment fluid is subsequentlypumped down the annulus between the wireline 102 and production casing 82, thetreating fluid is forced to enter perforations 240 and 241 and create new hydraulicfractures 242. The operations are then continued and repeated as appropriate for thedesired number of formation zones and intervals.

As alternatives to this sixth embodiment, the tractor System could beself-propelled, controlled by on-board computer Systems, and carry on-boardsignaling Systems such that it would not be necessary to attach cable or tubing forpositioning, control, and/or actuation of the tractor System. Furthermore, the variousBHA components could also be controlled by on-board computer Systems, and carryon-board signaling Systems such that it is not necessary to attach cable or tubing forcontrol and/or actuation of the components. For example, the tractor system and/orBHA components could carry on-board power sources (e.g., batteries), computerSystems, and data transmission/reception Systems such that the tractor and BHAcomponents could either be remotely controlled from the surface by remote signalingmeans, or altematively, the various on-board computer Systems could bepre-programmed at the surface to execute the desired sequence of operations when thedepîoyed in the wellbore.

In a seventh embodiment of this invention, abrasive (or erosive) fluid jets areused as the means for perforating the wellbore. Abrasive (or erosive) fluid jetting is acommon method used in the oil industry to eut and perforate downhole tubing strings 012171 -36- and other wellbore and wellhead components. The use of coiled tubing or jointedtubing as the BHA suspension means provides a flow conduit for deployment ofabrasive fluid-jet cutting technology. To accommodate this, the BHA is cmrfignrp.fiwith a jetting tool. This jetting tool allows high-pressure high-velocity abrasive (orerosive) fluid Systems or slunies to be pumped downhole through the tubing andthrough jet nozzles. The abrasive (or erosive) fluid cuts through the production casingwall, cernent sheath, and pénétrâtes the formation to provide flow pathcommunication to the formation. Arbitrary distributions of holes and slots can beplaced using this jetting tool throughout thecompletion interval during the stimulationjob. In general, abrasive (or erosive) fluid cutting and perforating can be readilyperformed under a wide range of pumping conditions, using a wide-range of fluidSystems (water, gels, oils, and combination liquid/gas fluid Systems) and with avariety of abrasive solid materials (sand, ceramic materials, etc.), if use of abrasivesolid material is required for the wellbore spécifie perforating application.

The jetting tool replaces the conventional select-fire perforating gun Systemdescribed in the previous six embodiments, and since this jetting tool can be on theorder of one-foot to four-feet in length, the height requirement for the surfacelubricator System is greatly reduced (by possible up to 60-feet or greater) whencompared to the height required when using conventional select-fire perforating gunassemblies as the perforating device. Reducing the height requirement for the surfacelubricator System provides several benefits including cost réductions and operationaltime réductions.

Figure 10 illustrâtes in detail a seventh embodiment of the invention where ajetting tool 310 is used as the perforating device and jointed tubing 302 is used tosuspend the BHA in the wellbore. In this embodiment, a mechanical compression-set,re-settable packer 316 is used as the re-settable sealing device; a mechanicalcasing-collar-locator 318 is used for BHA depth control and positioning; a one-wayfull-opening flapper-type check valve sub 304 is used to ensure fluid will not flow upthe jointed tubing 302; a combination shear-release fishing-neck sub 306 is used as asafety release device; a circulation/equalizafion port sub 308 is used to provide amethod for fluid circulation and also pressure equalization above and below the -37- 012171 mechanical compression-set, re-settable packer 316 nnder certain circumstances; and aone-way ball-seat check valve sub 314 is used to ensure that fluid may only flowupward from below fhe mechanical compression-set, re-settable packer 316 to thecirculation/equalization port sub 308.

The jetting tool 310 contains jet flow ports 312 that are used to accelerate anddirect the abrasive fluid pumped down jointed tubing 302 to jet with directimpingement on the production casing 82. In this configuration, the mechanicalcasing collar locator 318 is appropriately designed and connected to the mechanicalcompression-set, re-settable packer 316 such as to allow for fluid flow upward frombelow mechanical compression-set, re-settable packer 316 to thecirculation/equalization port sub 308. The cross-sectional flow area associated withthe flow conduits contained within the circulation/equalization port sub 308 are sizedto provide a substantially larger cross-sectional flow area than the flow area associatedwith the jet flow ports 312 such that the majority of flow within the jointed tubing 302or BHA preferentially flows through the circulation/equalization port sub 308 ratherthan the jet flow ports 312 when the circulation/equalization port sub 308 is in theopen position. The circulation/equalization port sub 308 is opened and closed byupward and downward axial movement of jointed pipe 302.

In this embodiment, jointed tubing 302 is preferàbly used with the mechanicalcompression-set, re-settable packer 316 since the mechanical compression-set, re-settable packer 316 can be readily actuated and de-actuated by vertical movementand/or rotation applied via the jointed tubing 302. Vertical movement and/or rotationis applied via the jointed tubing 302 using a completion rig-assisted snubbing unitwith the aid of a power swivel unit as the surface means for connection, installation,and removal of the jointed tubing 302 in to and out of the wellbore. It is noted thatthe surface hardware, methods, and procedures associated with use of a completionrig-assisted snubbing unit with a power swivel unit are common and well-known tothose skilled in the art for connection, installation, and removal of jointed tubingin/from a wellbore under pressure. Altematively, use of a completion rig with the aidof a power swivel unit, and stripping head in place,of the snubbing unit, couldaccommodate connection, installation, and removal of the jointed tubing in/from a -38- 012171 wellbore under pressure; again this is common and well-known to those sfcüled in theart for connection, installation, and removal of jointed tubing in/from a wellbore underpressure. It is further noted that the surface rig-up and plumbing configuration willinclude appropriate manifolds, piping, and valves to accommodate flow to, from, andbetween ail appropriate surface components/facilities and the wellbore, including butnot liwited to, the jointed tubing, annulus between jointed tubing and productioncasing, pumps, fluid tanks, and flow-back pits.

Since the mechanical compression-set, re-settable paclcer is actuated viajointed tubing 302 vertical movement and/or rotation, fluid can be pumped down thejointed tubing 302 without the necessity of additional control valves and/or isolationvalves that may otherwise be required if an inflatable packer was used as the re-settable sealing device. The interior of the jointed tubing 302 is used in this fashion toprovide an independent flow conduit between the surface and the jetting tool 310 suchthat abrasive fluid can be pumped down the jointed tubing 302 to the jetting tool 310.The jet flow ports 312 located on the jetting tool 310 then create a high velocityabrasive fluid jet that is directed to perforate the production casing 82 and cernentsheath 84 to establish hydraulic communication with the formation 86.

Figure 10 shows the jetting tool 310 has been used to place perforations 320to penetrate the first formation interval of interest, and that the first formation intervalof interest has been stimulated with hydraulic fractures 322. Figure 10 further showsthe jetting tool 310 has been repositioned within the wellbore and used to placeperforations 324 in the second formation interval of interest, and that the mechanicalcompression-set, re-settable packer 316 has been actuated to provide a hydraulic sealwithin the wellbore in advance of stimulating perforations 324 with the second stageof the multi-stage hydraulic proppant fracture treatment.

It is noted that the jet flow ports 312 may be located within approximately six-inches to one-foot of the mechanical compression-set, re-settable packer 316 such thatafter pumping the second proppant fracture stage, should proppant accumulation onthe top of the mechanical compression-set, re-settable packer 316 be of concem, non-abrasive and non-erosive fluid can be pumped down the jointed tubing 302 andthrough the jet flow ports 312 and/or the circulation/equalization port sub 308 as -39- 012171 necessaiy to clean proppant from the top of the mechanical compression-set,re-settable packer 316. Furthermore, the jetting tool 310 may be rotated (when themechanical compression-set, re-settable packer 316 is not actuated) using the jointedtubing 302 which may be rotated with the surface power swivel unit to further help toclean proppant accumulation that may occur above the mechanical compression-set,re-settable packer 316. Since the perforations are created using a fluid jet, perforationburrs will not be created. Since perforation burrs are not présent to potentiallyprovide additional wear and tear on the elastomers of the mechanical compression-setre-settable packer 316, the longevity of the mechanical compression-set re-settablepacker 316 may be increased when compared to applications where perforation buirsmay exist.

It is further noted that the flow control provided by the one-way ball-seatcheck valve sub 314 and the one-way full-opening flapper-type check valve sub 304only allows for pressure equaîization above and below the mechanicalcompression-set, re-settable packer 316 when the pressure below the mechanicalcompression-set, re-settable packer 316 is larger than the pressure above themechanical compression-set, re-settable packer 316. In circumstances when thepressure above the mechanical compression-set, re-settable packer 316 may be largerthan the pressure below the mechanical compression-set, re-settable packer 316, thepressure above the mechanical compression-set, re-settable packer 316 can be readilyreduced by performing a controlled flow-back of the just stimulated zone using theannulus between the jointed tubing 302 and the production casing 82; or bycirculation of lower density fluid (e.g., nitrogen) down the jointed tubing 302 and upthe annulus between the jointed tubing 302 and production casing 82.

The one-way full-opening flapper-type check valve sub 304 is preferred as thistype of design accommodâtes unrestricted pumping of abrasive (or erosive) fluiddownhole, and furthermore allows for passage of control balls that, depending on thespécifie detailed design of individual BHA components, may be dropped from thesurface to control fluid flow and hydraulics of individual BHA components or providefor safety release of the BHA. Depending on the spécifie tool design, many different -40- Οι 2171 valving configurations could be deployed to provide the fimctionality provided by thefiow control valves described in tins embodiment.

As alternatives to tins seventb embodiment, a sub containing a nipple could beinclnded which could provide the capability of suspending and holding othermeasurement devices or BHA components. This nipple, for example, could hold aconventional casing-collar-locaior and gamma-ray tool that is deployed via wirelineand seated in the nipple to provide additional diagnostics of BHA position andlocation of formation intervals of interest. Additionally, multiple abrasive jettingtools can be deployed as part of the BHA to control perforation cutting characteristics,such as hole/slot size, cutting rate, to accommodate various abrasive materials, and/orto provide system redundancy in the event of prématuré component failure.

It will be recognized by those skilled in the art that many different componentscan be deployed as part of the bottomhole assembly. The bottomhole assembly maybe configured to contain instrumentation for measurement of réservoir, fluid, andwellbore properties as deemed désirable for a given application. For example,température and pressure gauges could be deployed to measure downhole fluidtempérature and pressure conditions during the course of the treatment; a densitometercould be used to measure effective downhole fluid density (which would beparticularly useful for determining the downhole distribution and location of proppantduring the course of a hydraulic proppant fracture treatment); and. a radioactivedetector system (e.g., gamma-ray or neutron measurement Systems) could be used forlocating hydrocarbon bearing zones or identifying or locating radioactive materialwithin the wellbore or formation.

Depending on the spécifie bottomhole assembly components and whether theperforating device créâtes perforation holes witih buirs that may damage the sealingmechanism, the bottomhole assembly could be configured with a "perforation burrremoval" tool that would act to scrape and remove perforation'burrs from the casingwall.

Depending on the spécifie bottomhole assembly components and whetherexcessive wear of bottomhole assembly components may occur if the assembly is runin contact with the casing wall, centralizer subs could be deployed on the bottomhole -41- 012171 assembly to provide positive mechanical positioning of the assembly and prevent orminiimze the potentiel for damage due to the assembly running in contact with thecasing wall.

Depending on the spécifie bottomhole assembly components and whether theperforation charges create severe shock waves and induce undue vibrations whenfired, the bottomhole assembly may be configured with vibration/shock dampeningsubs that would eliminate or minimize any adverse effects on system performance dueto perforation charge détonation.

Depending on the deployment system used and the objectives of a particularjob, perforating devices and any other desired BHA components may be positionedeither above or below the re-settable sealing mechanism and in any desired orderrelative to each other. The deployment system itself, whether it be wireline, electricline, coiled tubing, conventional jointed tubing, or downhole tractor may be used toconvey signais to activate the sealing mechanism and/or perforating device. ït wouldalso be possible to suspend such signaling means within conventional jointed tubingor coiled tubing used to suspend the sealing and perforating devices themselves.Altematively, the signaling means, whether it be electric, hydraulic, or other means,could be run in the hole extemally to the suspension means or even housed in orcomprised of one or more separate strings of coiled tubing or conventional jointedtubing.

With respect to treatments that use high viscosity fluid Systems in wells deeperthan about 8,000 feet, several major technological and économie benefîts areimmediately derived from application of this new invention. Reducing the frictionpressure limitations allows treatment of deeper wells and reduces the requirement forspécial fracture fluid formulations. Friction pressure limitations are reduced oreliminated because the high viscosity fluid can be pumped down the aunulus betweenthe coiled tubing or other suspension means and production casing. Since frictionpressure limitations can be reduced or eliminated from that experienced with pumpinghigh viscosity fluid Systems down the interior of coiled tubing, well depths where thistechnique can be applied are substantially increased. For example, assuming1-1/2-inch coiled tubing deployed in a 5-1/2-inch outer diameter 17-pound-per-foot 012171 -42- casing, the effective cross-sectional flow area is approximately équivalent to a 5-inchouter diameter casing string. With this effective cross-sectional flow area, well depthson the order of 20,000 feet or greater could be treated and higher pump rates (e.g., onthe order of 10 to 30-barrels-per-minute or more) could be achieved for effective 5 proppant transport and hydraulic fracturing using high viscosity fluids.

Since the annulus typically may hâve greater équivalent flow area, conventional fracturing fluids can be used, as opposed to spécial low-viscosity fluids(such as Dowell-Schlumbergefs ClearFrac™ fluid) used to reduce friction pressuredrop through coiled tubing. The use of conventional fracturing fluid technology 10 would then allow treatment of formations with températures greater than 250°F, abovewhich currently available higher-cost specialty fluids may begin to dégradé.

The sealing mechanism used could be an inflatable device, a mechanicalcompression-set re-settable packer, a mechanical compression-set straddle-packerdesign, cup-seal devices, or any other alternative device that may be deployed via a 15 suspension means and provides a re-settable hydraulic sealing capability or équivalentfunction. Both inflatable and compression set devices exist that provide radialclearance between seals and casing wall (e.g., on the order of 0.25-inches to 1-inch forinflatable devices or 0.1 - 0.2 inches for compression-set devices) such that seal wearand tear would be drastically reduced or eliminated altogether. In a preferred 20 embodiment of this invention, there would be suffrcient clearance between the sealing mechanism in its deactivated State and the casing wall to allow rapid movement intoand out of the wellbore without significant damage to the sealing mechanism orwithout pressure control issues related to surging/swabbing the well due to toolmovement. The increased clearance between the seal surface and the casing wall 25 (when the seal is not actuafed) would also allow the coiled tubing/BHA to be trippedin and out of the hole at much faster speeds than are possible with currently availablecoiled tubing Systems. In addition, to mini-n-rize potential undesirable seal wear andtear, in a preferred embodiment, the perforating device would accommodatepeiforating the casing wall such that a perforation hole with a relatively smooth edge 30 would be achieved. Altematively, the mechanical re-settable sealing mechanism maynot need to provide a perfect hydraulic seal and for ,example, could retain a small gap -43- 012171 around the circumference of the device. This small gap could be sized to provide asealing mechanism (if desired) whereby proppant bridges across the small gap andprovides a seal (if desired) that can be removed by fluid circulation. Furthermoredepending on the spécifie application, it is possible that a stimulation job couldproceed in an economically viable fashion even if a perfect hydraulic seal was notobtained with the mechanical re-settable sealing mechanism.

Since the perforating device is deployed simultaneously with the re-settablesealing mechanism, ail components can be depth controlled at the same time by thesame measurement standard. This éliminâtes depth control problems that existingmethods expérience when perforation operations and stimulation operations areperformed using two different measurement Systems at different times and differentwellbore trips. Very précisé depth control can be achieved by use of a casing-collar-locator, which is the preferred method of depth control.

The gross height of each of the individual perforated target intervals is notlimited. This is in contrast to the problem that existing coiled tubing Systems possessusing a straddle-packer like device that limits application to 15 - 30 feet of perforatedinterval height.

Since permanent bridge plugs are not necessarily used, the incrémental costand wellbore risk associated with bridge plug drill-out operations is eliminated.

If coiled tubing is used as the deployment means, it is possible that the coiledtubing string used for the stimulation job could be hung-off in the wellhead and usedas the production tubing string, which could resuit in significant cost savings byeliminating the need for rig mobilisation to the well-site for installation ofconventional production tubing string comprised of jointed tubing.

Controlling the sequence of zones to be treated allows the design of individualtreatment stages to be optimized based on the characteristics of each individual zone.Furthermore, the potentiaî for sub-optimal stimulation because multiple zones aretreated simultaneously is essentially eliminated by having only one open set ofperforations exposed to each stage of treatment. For example, in the case of hydraulicfracturing, this invention may minimize the potentiaî for overfiush or sub-optimalplacement of proppant into the fracture. Also, if a problem occurs such that the -44- 012171 treatment must be terminated, the up-hole zones to be stimulated hâve not beencompromised, since they hâve yet to be perforaied. This is in contrast to conventionalbail sealer or coiled tubing stimulation methods, where ail perforations must be shotprior to the job. Should the conventional coiled tubing job fail, it may be extremelydiffîcult to efîectively divert and stimulate over a long completion interval.Additionally, if only one set of perforations is open àbove the sealing element, fluidcan be circulated without the possibility of breaking down the other multiple sets ofopen perforations above the top sealing element as could occur in the conventionalcoiled tubing job. This can minimise or eliminate fluid loss and damage to theformation when the bottomhole circulation pressure would otherwise exceed theformation pore pressure.

The entire treatment can be pumped in a single trip, resulting in significantcost savings over other techniques that require multiple wireline or rig work to trip inand out of the hole in between treatment stages.

The invention can be applied to multi-stage treatments in deviated andhorizontal wellbores. Typically, other conventional diversion technology in deviatedand horizontal wellbores is more challenging because of the nature of the fluidtransport of the diverter material over the long intervals typically associated withdeviated or horizontal wellbores.

Should a screen-out occur during the fracture treatment, the invention providesa method for sand-laden fluid in the annulus to be immediately circulated out of thehole such that stimulation operations can be recommenced without having to trip thecoiled tubingZBHA out of the hole. The presence of the coiled tubing System providesa means to measure bottomhole pressure after perforating or during stimulationoperations based on pressure calculations involving the coiled tubing string undershut-in (or low-flow-rate) conditions.

The presence of the coiled tubing or conventional jointed tubing System, ifused as tire deployment means, provides a means to inject fluid downholeindependently from the fluid injected in the annulus. This may be useful, forexample, in additional applications such as: (a) keeping the BHA sealing mechanismand flow ports clean of proppant accumulation (that could possibly cause tool -45- 012171 sticking) by pumping fluid downhole ai a nominal rate to clean o£f the sealingmechanism and flow ports; (b) downhole mixing applications (as discussed furtherbelow); (c) spotting of acid downhole during perforating to aid perforation hole clean-up and communication with the formation; and (d) independently stimulating twozones isolated from each other by the re-settable sealing mechanism. As such, iftubing is used as the deployment means, depending on the spécifie operations desiredand ihe spécifie botiomhoîe assembly components, fluid could be circuîated downholeai ail times; or only when tire sealing element is energized, or only when the sealing i element is not energized; or while equalization ports are open or closed. Dependingon the spécifie bottomhole assembly components and the spécifie design of downholeflow control valves, as may be nsed for example as intégral components ofequalization ports subs, circulation port subs or flow port subs, downhole flow controlvalves may be operated by wireline actuation, hydraulic actuation, flow actuation,"j-latch" actuated, sliding-sleeve actuated, or by many other means known to thoseskilled in the art of operation and actuation of downhole flow control valves.

The coiled tubing System still allows for controlled flowback of individualtreatment stages to aid clean up and assist fracture closure. Flowback can beperformed up the annulus between the coiled tubing and the production casing, oraltematively, flowback may even be performed up the coiled tubing string if excessiveproppant flowback were not to be considered a problem.

The perforating device may be comprised of commercially-availableperforating Systems. These gun Systems could include what will be refeired to hereinas a "select-fire” System such that a single perforation gun assembly is comprised ofmultiple charges or sets of perforation charges. Each individual set of one or moreperforation charges can be remotely controlled and frred from the surface usingelectric, radio, pressure, fiber-optic or other actuation signais. Each set of perforationcharges can be designed (number of charges, number of shots per foot, hole size,pénétration cbaracteristics) for optimal perforation of the individual zone that is to betreated with an individual stage. With crûrent select-fire gun technology, commercialgun Systems exist that could allow on the order of 30 to 40 intervals to be perforatedsequentially in a single downhole trip. Guns can be pre-sized and designed to provide -46- 012171 for firing of multiple sets of perforations. Guns can be located at any location on thebottomhole assembly, including either above or below the mechanical re-settablesealing mechanism.

Intervals may be grouped for treatment based on réservoir properties,treatment design considérations, or equipment limitations. After each group ofintervals (preferably 5 to approximately 20), at the end of a workday (often defîned bylighting conditions), or if difficulties with sealing one or more zones are encountered,a bridge plug or other mechanical device would preferably be used to isolate the groupof intervals already treated from the next group to be treated. One or more select-fireset bridge plugs or fracture baffles could be run in conjunction with the bottomholeassembly and set as desired during the course of the completion operation to providepositive mechanical isolation between perforated intervals and eliminate the need for aseparate wireline run to set mechanical isolation devices or diversion agents betweengroups of fracture stages.

In general, the inventive method can be readily employed in productioncasings of 4-1/2 inch diameter to 7-inch diameter with existing commerciallyavailable perforating gun Systems and mechanical re-settable sealing mechanisms.The inventive method could be employed in smaller or larger casings with mechanicalre-settable sealing mechanisms appropriately designed for the smaller or largercasings.

If select-fire perforating guns are used, each individual gun may be on theorder of 2 to S feet in length, and contain on the order of 8 to 20 perforating chargesplaced along the gun tube at shot density ranging between 1 and 6 shots per foot, butpreferably 2 to 4 shots per foot In a preferred embodiment, as many as 15 to 20individual guns could be stacked one on top of another such that the assembled gunSystem total length is preferably kept to less than approximately 80 to 100 feet. Thistotal gun length can be run into the wellbore using a readily-available surface crâneand lubricator System. Longer gun lengths could also be used, but may requireadditional or spécial surface equipment depending on the total number of guns thatwould make up the complété perforating device. It is noted that in some uniqueapplications, gun lengths, number of charges per gun, and shot density could be -47- 012171 greater or less than as specified above as final perforating System design wonld beimpacted by the spécifie formation characteristics présent in the wellbore tostimulated

Jn order to minimize the total length of the gun System and BHA, it may bedésirable to use multiple (two or more) charge carriers uniformîy distributed aroundand strapped, welded, or otherwise attached to the coiled tubing or connected belowthe mechanical re-settable sealing mechanism. For example, if it were desired tostimulaie 30 zones, where each zone is perforated with a 4-ft gun, a single gunassembly would resuit in a total length. of approximately 150 feet, winch may beimpractical to handle at the surface. Altematively, two gun assemblies locatedopposite one another on the coiled tubing could be deployed, where each assemblycould contain 15 guns, and total length could be approximately 75-ίεεζ which couldreadily be handled at the surface with existing lubricator and crâne Systems.

An alternative arrangement for the perforating gun or guns would be to locateone or more guns àbove the re-settable mechanical sealing mechanism. There couldbe two or more separate gun assemblies attached in such a way that the charges wereoriented away from the components on the bottomhole assembly or the coiled tubing.It could also be a single assembly with charges loaded more densely and firingmechanisms designed to simultaneously fire only a subset of the charges within agiven interval, perhaps ail at a given phase orientation.

Although the perforating device descrïbed in this embodiment used remotelyfired charges or fluid jetting to peiforate the casing and cernent sheath, alternativeperforating devices including but not limited to Chemical dissolution ordriUiug/milling cutting devices could be used within the scope of this invention forthe purpose of creating a flow path between the wellbore and the surroundingformation. For the purposes of this invention, the tenu "perforating device" will beused broadly to include ail of the above, as well as any actuating device suspended inthe wellbore for the purpose of actuating charges or other perforating means that maybe conveyed by the casing or other means extemal to the bottomhole assembly orsuspension method used to support the bottomhole assembly. -48- 012171

The BHA could contain a downhole motor or other mechanism to providerotation/torque to accommodate actuation of mechanical seabng mechanismsrequiring rotation/torque for actuation. Such a device, in conjunction with anorienting device (e.g., gyroscope or compass) could allow oriented perforating suchthat perforation holes are placed in a preferred compass direction. Altematively, ifconventional jointed tubing were to be used, it is possible that rotation and torquecould be transmitted downhole by direct rotation of the jointed tubing using rotationdrive equipment that may be readily available on conventional workover rigs.Downhole instrumentation gauges for measurement of well conditions (casing collarlocator, pressure, température, pressure, and other measurement gauges) for real-timedownhole monitoring of stimulation job parameters, réservoir properties, and/or wellperformance could also be deployed as part of the BHA.

In addition to the re-settable mechanical diversion device, other diversionmaterial/devices could be pumped downhole during the treatment including but notlimited to bail sealers or particulates such as sand, ceramic material, proppant, sait,waxes, resins, or other organic or inorganic compounds or by alternative iluid Systemssuch as viscosified fluids, gelled fluids, foams, or other chemically formulated fluids.or other injectable diversion agents. The additional diversion material could be usedto help mini-mi ze the duration of the stimulation treatment as some time savings couldbe realized by reducing the number of times the mechanical diversion device is set,while strill achieving diversion capabilities over the multiple zones. For example in a3,000 foot interval where individual zones nominally 100 feet apart are to be treated,it may be désirable to use the re-settable mechanical diversion device woriring in 500foot incréments uphole, and then divert each of the six stages with a diverting agentcanied in the treating fluid. Altematively, limited entry techniques could be used formultiple intervals as a subset of the gross interval desired to be treated. Either ofthese variations would decrease the number of mechanical sets of the mechanicaldiversion device and possibly extend its effective life.

If a tubing string is used as the deployment means, the tubing allows fordeployment of downhole mixing devices and ready application of downhole mixingtechnology. Specifically, the tubing string can be used to pump Chemicals downhole -49- 012171 and througb. the flow ports in the bottomhole assembly to subsequently mix with tiaefluid pumped in the tubing by production casing annulus. For example, during ahydrauïic fracturing treatment, it may be désirable to pump nitrogen or carbon dioxidedownhole in the tubing and hâve it mix with the treatment fluid downhole, such thatnitrogen-assisted or carbon dioxide-assisted flowback can be accommodated.

This method and apparatus could be used for treatment of vertical, deviated, orhorizontal wellbores. For example, the invention provides a method to generatemultiple vertical (or somewhat vertical) fractures to intersect horizontal or deviatedwellbores. Such a technique could enable économie completion of multiple wellsfrom a single pad location. Treatment of a multi-lateral well could also be performedwherein the deepest latéral is treated first; then a plug is set or sleeve actuated toisolate this lowest latéral; the next up-hole latéral is then treated; another plug is set orsleeve actuated to isolate this latéral; and the process repeated to treat the desirednumber of laterals within a single wellbore.

If select-fire perforating guns are used, although désirable from the standpointof maximizing the number of intervals that can be treated, the use of short guns(i.e., 4-ft length or less) could limit well productivity in some instances by inducingincreased pressure drop in the near-wellbore réservoir région when compared to use oflonger guns. Well productivity could similarly be limited if only a short interval(i.e., 4-ft length or less) is perforated using abrasive jetting. Potential for excessiveproppant flowback may also be increased leading to reduced stimulation effectiveness.Flowback would preferably be performed at a controlled low-rate to limit potentialproppant flowback. Depending on flowback results, resin-coated proppant oralternative gun configurations could be used to improve the stimulation effectiveness.

In addition, if tubing or cable are used as the deployment means to helpmitigate potential undesirable proppant érosion on the tubing or cable from directimpingement of the proppant-laden fluid when pumped into the side-outlet injectionports, an "isolation device” can be rigged up on the wellhead. The isolation devicemay consists of a fiange with a short length of tubing attached that runs down thecenter of the wellhead to a few feet below the injection ports. The bottomholeassembly and tubing or cable are run intérim to the isolation device tubing. Thus the 012171 -50- tubing of the isolation device deflects the proppant and isolâtes the tubing or cablefrom direct impingement of proppant. Such an isolation device would consist of anappropriate diameter tubing such that it would readily allow the largest outer diameterdimension associated with the tubing or cable and bottomhole assembly to passthrough unhindered. The length of the isolation device would be sized such that in theevent of damage, the lower master fracture valve could still be closed and theweïlhead rigged down as necessary to remove the isolation tool. Depending on thestimulation fluids and the method of injection, an isolation device would not beneeded if érosion concems were not présent. Although field tests of isolation deviceshâve shown no érosion problems, depending on the job design, there could be somerisk of érosion damage to the isolation tool tubing assembly resulting in difficultyremoving it If an isolation tool is used, preferred practices would be to maintainimpingement velocity on the isolation tool substantially below typical erosionallimits, preferably below about 180 ft/sec, and more preferably below about 60 ft/sec.

Another concem with this technique is that prématuré screen-out may occur iffluid displacement during pumping is not adequately measured as it may be difficultto initiate a fracture with proppant-laden fluid across the next zone to be perforated. Itmay be préférable to use a KC1 fluid or some other non-gelled fluid or fluid System forthe pad rather than a gelled pad fluid to better initiate fracturing of the next zone.Pumping the job at a higher rate with a non-gelled fluid between stages to achieveturbulent flush/sweep of the casing will minimize the risk of proppant screen-out.Also, contingency guns available on the tool string would allow continuing the jobafter an appropriate wait time.

Although the embodiments discussed above are primarily related to thebénéficiai effects of the inventive process when applied to hydraulic fracturingprocesses, this should not be interpreted to limit the claimed invention which isapplicable to any situation in which perforating and performing other weiïboreoperations in a single trip is bénéficiai. Those skilled in the art will recognize thatmany variations not specifically mentioned in the examples will be équivalent infunction for the purposes of this invention.

Claims

51 012171 CLAIMS

1. A method of perforating and treating multiple intervals of one or moresubterranean formations intersected by a wellbore, said method comprising: (a) deploying a bottom-hole assembly ("BHA") within said wellbore, saidBHA having a perforating device, a sealing mechanism and at least onepressure equalization means; (b) using said perforating device to perforate an interval of said one ormore subterranean formations; (c) actuating said sealing mechanism so as to establish a hydraulic seal insaid wellbore; (d) pumping a treating fluid in said wellbore and into the perforationscreated by said perforating device, without removing said perforatingdevice from said wellbore; (e) establishing pressure communication between the portions of thewellbore above and below said sealing mechanism through said at leastone pressure equalization means; (f) releasing said sealing mechanism; and (g) repeating steps (b) through (f) for at least one additional interval ofsaid one or more subterranean formations.
2. A method of perforating and treating multiple intervals of one or moresubterranean formations intersected by a wellbore, said method comprising: (a) deploying a bottom-hole assembly ("BHA”) within said wellbore, saidBHA having at least one perforating device and at least one sealingmechanism, said perforating device being positioned below saidsealing mechanism; 52 012171 10 15 (b) using said at least one perforating device to perforate an interval of saidone or more subterranean formations; (c) actuating said at least one sealing mechanism so as to establish ahydraulic seal in said wellbore; (d) pumping a treating fluid in said wellbore and into the perforationscreated by said perforating device, without removing said perforatingdevice from said wellbore; (e) releasing said sealing mechanism; and (f) repeating steps (b) through (e) for at least one additional interval ofsaid one or more subterranean formations.
3. The method of Claim 2 wherein said perforating device has no washing fluidflow passage provided therethrough.
4. The method of Claim 1 or 2 wherein the BHA is repositioned in said wellboreand said sealing mechanism is actuated to establish a hydraulic seal below saidperforated interval.
5. A method of perforating and treating multiple intervals of one or moresubterranean formations intersected by a wellbore, said multiple intervalsincluding a deepest target interval and sequentially shallower target intervals,said method comprising: 5 (a) deploying a bottom-hole assembly ("BHA") within said wellbore, said BHA having a perforating device and a sealing mechanism, saidperforating device positioned below said sealing mechanism; (b) using said perforating device to perforate said deepest target interval ofsaid one or more subterranean formations; 53 012171 10 15 20 (c) pumping a treating fluid in said wellbore and into the perforationscreated in said deepest target interval by said perforating devicewithout removing said perforating device from said wellbore; (d) positioning said BHA in said wellbore and using said perforatingdevice to perforate the next sequentially shallower target interval ofsaid one or more subterranean formations; (e) repositioning said BHA in said wellbore and actuating said sealingmechanism to hydraulically isolate the perforations created in said nextsequentially shallower target interval from the perforated deepest targetinterval; (f) pumping a treating fluid in said wellbore and into the perforationscreated in said next sequentially shallower target interval by saidperforating device without removing said perforating device from saidwellbore; (g) releasing said sealing mechanism; and (h) repeating steps (d) through (g) for at least one additional sequentiallyshallower target interval of said one or more subterranean formationswherein the perforations created in said at least one additionalsequentially shallower target intervals are hydraulically isolated fromthe perforated intervals below. 25 54 012171
6. An apparatus for use in perforating and treating multiple intervals of one ormore subterranean formations intersected by a wellbore, said apparatuscomprising: (a) a bottom-hole assembly (BHA), adapted to be deployed in saidwellbore by a deployment means, said BHA having at least oneperforating device for sequentially perforating said multiple intervals,at least one sealing mechanism and at least one pressure equalizationmeans; and (b) said sealing mechanism capable of establishing a hydraulic seal in saidwellbore, said pressure equalization means capable of establishingpressure communication between portions of said wellbore above andbelow said sealing mechanism, and said sealing mechanism furthercapable of releasing said hydraulic seal to allow said BHA to move to adifferent position within said wellbore, thereby allowing each of saidmultiple treatment intervals to be treated separately ffom said othertreatment intervals.
7. An apparatus for use in perforating and treating multiple intervals of one ormore subterranean formations intersected by a wellbore, said apparatuscomprising: (a) a bottom-hole assembly (BHA), adapted to be deployed in saidwellbore by a deployment means, said BHA having at least oneperforating device for sequentially perforating said multiple intervalsand at least one sealing mechanism, said perforating device beingpositioned below said sealing mechanism; and (b) said sealing mechanism capable of establishing a hydraulic seal in saidwellbore, and further capable of releasing said hydraulic seal to allowsaid BHA to move to a different position within said wellbore, thereby 55 012171 allowing each of said multiple treatment intervals to be treatedseparately from said other treatment intervals.
8. The apparatus of Claim 7 wherein said perforating device has no washing fluidflow passage provided therethrough.