Patent Publication Number: US-2004040707-A1

Title: Well treatment apparatus and method

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS  
       [0001] Not Applicable.  
       STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT  
       [0002] Not Applicable.  
       BACKGROUND OF THE INVENTION  
       [0003] 1. General Field of the Invention  
       [0004] The present invention relates generally to tools and methods used in treating subterranean wells and, in a preferred embodiment thereof, relates more particularly to apparatus and methods for conducting well stimulation and formation fracturing operations in subterranean wells.  
       [0005] 2. Background Information  
       [0006] A potentially productive geological formation beneath the earth&#39;s surface often contains a sufficient volume of valuable fluids, such as hydrocarbons, but also may be characterized as having a very low permeability. “Permeability” is a term relating to a quality of a geological formation which describes the ability of fluids to move about through the formation. The hydrocarbons are contained in the formation&#39;s pores, and a formation may be described in terms of its “porosity.” If a formation&#39;s porosity is low, meaning that the pores are not sufficiently interconnected, the fluids cannot migrate through the formation and, thus, cannot be brought to the earth&#39;s surface without a structural modification or stimulation of the production zone.  
       [0007] When it is desired to recover hydrocarbons from a formation having low permeability, it becomes necessary to “stimulate” the well, meaning to artificially increase the formation&#39;s permeability. This is typically accomplished by “fracturing” the formation, a practice which is well known in the art and for which purpose many methods have been conceived. Basically, fracturing is achieved by applying sufficient fluid pressure to the formation to cause it to crack or fracture, hence the term “fracturing” or simply “fracing.” The desired result of this process is that the cracks interconnect the formation&#39;s pores and allow the hydrocarbons to be brought out of the formation and to the surface. Typically in the fracing process, sand or another proppant is pumped into the formation to keep the cracks or voids open to allow the desired fluid migration. Other types of well treatment operations are used to enhance production, including acidizing and hydraulic jetting of the formation. Like fracing, these methods also involve pumping fluids downhole and into the formation.  
       [0008] In completing a well for production, the borehole in the earth is cased by tubular casing which is cemented within the borehole. To allow the formation fluids to flow into the production bore in the casing, the cased borehole is perforated in regions adjacent to the zones in the formation that are believed to be productive. To perforate the cased borehole, a perforating assembly mounted on the lower end of a tubular work string or wire line is lowered into the well bore. The perforation tool or “gun” assembly is then detonated to create a series of spaced perforations extending outwardly through the well casing, the cement holding the casing in place in the wellbore, and into the production zone. The discharged gun assembly is then pulled up with the work string to complete the perforating trip.  
       [0009] Using previously proposed apparatus and methods, the general sequence of steps needed to stimulate or frac a production zone includes lowering into the well a tubular proppant discharge member and one or more packers on a work string. The proppant discharge member includes discharge or exit ports formed therein, the discharge ports being located in close proximity to the gun-created perforations that extend outwardly through the perforated casing. Proppant slurry is then pumped down the work string and discharged through the ports in the discharge member where it flows outwardly through the perforations into the surrounding production zone. Once the appropriate amount of proppant has been injected into the formation, the work string is then removed from the wellbore to complete the stimulation trip and to initiate the production of the well  
       [0010] This previously proposed perforation and proppant fracturing technique has several well known and heretofore unavoidable problems, limitations and disadvantages. For example, when the proppant slurry discharge member is lowered into the well bore, it is difficult to obtain a precise alignment (in both the axial and angular directions) between the discharge ports in the discharge member and the perforations in the casing. The usual result is that some degree of misalignment exists between the discharge ports and the perforations. Because of such misalignment, the proppant must follow a tortuous path on its way to entering the perforations after it is discharged from the workstring. Because of the highly abrasive character of proppant slurry and because the slurry is under very high pressure, this tortuous flow path can cause severe abrasion and wear with respect to the components of the bottom hole assembly and to the casing.  
       [0011] Use of the above-described prior technique also limits the ability to isolate multiple production zones from one another—a requirement that may be necessary due to the fact that different zones may require different fracturing pressures, different types of fracturing fluids, and different amounts of proppant.  
       [0012] Isolating and fracing zones individually within a perforated interval that contains multiple zones is important due to other considerations as well. For example, in one type of prior fracing method, a relatively long interval with many producing zones is treated in a single fracing procedure after the entire interval had been perforated. A workstring having a ported discharge sub through which the fracing fluids are pumped is placed in the well bore in the vicinity of the perforated interval. The workstring includes a pair of packers spaced apart by a distance greater than the length of the entire perforated interval. One packer is set above and one below the interval, and the fracing slurry is then pumped downhole at a relatively high pressure so that the fluid, theoretically, is forced through all of the perforations and into all of the potentially productive zones in a single operation. In many such operations, however, the results were not satisfactory. Typically, certain of the producing zones in the isolated or “packed off” interval have weaker formation strength than the others. As a result, the fracing fluids tend to flow into the formation with the weakest formation strength, i.e., the formation with the highest permeability to fluids. Thus, because little fracing fluid actually enters the other zones when this occurs, certain potentially productive zones are not adequately stimulated or fraced, and do not thereafter produce to the desire degree.  
       [0013] Attempts have also been made to frac and treat potentially productive formations or zones one at a time. The procedure employed tends to eliminate the disadvantages associated with fracing simultaneously over a relatively large interval. To accomplish this, each potentially productive zone is provided with its own set of perforations through the well casing. Using a workstring with a ported discharge sub and a “straddle packer assembly,” the work string is placed in the well bore with the packers straddling the first interval to be fraced. The packers are then actuated (set) so as to isolate that particular zone from the other zones such that it can be treated individually. Typically, the lower most zone is treated first. Thereafter, the packers are released (unset) and the work string raised to the next zone to be treated. As before, the packers are then set so as to straddle the perforations in that zone, and the zone is individually treated. Thereafter, the workstring is raised to still another zone. This method and apparatus for treating zones individually generally produces higher production rates.  
       [0014] The method and apparatus for individually treating zones is typically performed with a work string comprised of either jointed metal pipe or metal coiled tubing. The discharge member or ported sub is positioned at the lower end of the workstring. The method thus described, however, has inherent limitations. First, to succeed, it is important that the packers completely straddle the perforations and not be set in the perforated region. If either packer is set in an area having perforations, the fracing fluid flowing out of the ported sub and through the perforations into the formation will flow back into the wellbore annulus through the perforations that are beyond the region being isolated by the straddle packers. Turbulence caused by the abrasive fracing fluid flowing back into the annulus creates a pressure differential across the packers and tends to erode or “wash out” and ruin the packer assembly, an event that frustrates the fracturing operation.  
       [0015] Additionally, it is important that the packers not be set within a casing joint, but instead be set in the blank pipe extending between the casing joints. Typically, there are gaps between the terminal ends of adjacent casing sections at the casing joints. If the packers are set on those gaps, then the packers will not seal properly and hold pressure to isolate the intended interval. When this occurs, the packers have not isolated and sealed off the annulus in the desired interval, and the fracing fluid can flow out of the isolated annulus and into the annulus extending beyond the packers. This condition can cause the packers to wash out and erode. Further, depositing large quantities of proppant above the packer assembly may cause the assembly to stick in the hole or to otherwise become difficult to relocate. Accordingly, it is critical to know the location of the perforations and the casing joints and to ensure that the straddle packers are properly located and not set in perforations or a casing joint. Unfortunately, properly positioning the packers with respect to the perforations and casing joints has been difficult to achieve.  
       [0016] In shallow wells, it is easier to record depth in the well and to more accurately position at particular depths tools that are lowered via the work string. This is because in shallow wells, the work string have less weight and the downhole temperatures are not so great as to cause extreme changes in the pipe length due to stretching or contracting of the pipe as a result of weight or temperature. Accordingly, the depth of casing joints and perforations may be discerned and recorded with reasonable accuracy in shallow wells given that the length of the work string used in forming the perforations, for example, may be accurately determined by counting the pipes making up the string. Likewise, the length of a work string used to conduct a fracing operation in a shallow well may also be accurately determined by recording the length of tubing or number of pipes (multiplied by each pipe&#39;s length) such that the ported discharge sub may be properly positioned adjacent to the perforations, and the packers may be properly positioned in the blank pipe. For purposes of this application, a “shallow” well is defined as a well having a depth of 3000 feet or less and a “deep well” is a well having a depth of more than 3000 feet.  
       [0017] For deep wells, depth control is more problematic. For example, if the work string is jointed pipe, the weight of the work string extending into a deep well tends to cause the string to stretch such that its length, and thus the location of the downhole tool it supports, may not provide an accurate depth indication. Further, the work string will tend to expand and contract with downhole temperatures which also introduces inaccuracies in the length of the string and thus the actual depth of the tools.  
       [0018] In another example, when the workstring is coiled tubing and it is run into a deep well, it tends to bend and curl within the cased borehole, such that the exact distance from the surface to the downhole tool does not equal the length of coiled tubing that has been injected into the well. Further, the deeper the well, the higher the temperature and the greater the expansion of the coiled tubing. In a shallow well, the upper and lower straddle packers may be only ten feet apart, for example. Using closely-spaced straddle packers in a deep well however, and considering the expansion and contraction of the coiled tubing, as well as the tendency for the coiled tubing to bend and curl in the borehole, it is extremely difficult to determine exactly where the packers and fracing assembly are in relation to casing joints and the perforations.  
       [0019] Although conventional metal coiled tubing has been employed in shallow wells in certain fracing operations, it is not feasible in certain deep wells. For example, most conventional metal coiled tubing cannot withstand a 12,000 psi differential pressure as may be encountered at the surface when conducting deep well fracing operations. Further, metal coiled tubing is relatively heavy and transporting the number of spools of coiled tubing required for the operation and injecting and withdrawing the tubing from a deep well requires specially designed, heavy duty equipment  
       [0020] Furthermore, even if the depth of the fracing assembly were somehow to be precisely known, there still exist problems that are introduced due to inaccuracies in determining the actual depth of the perforations. As stated above, the step of perforating the well typically includes recording the depth and location of the perforations; however, using perforation equipment with wire line, jointed pipes and coiled tubing nevertheless does not always provide accurate depth measurements, due again to the tendency of the wireline, pipe and tubing to expand with weight and downhole temperatures, and to bend or coil in the borehole.  
       [0021] Another problem inherent in fracing operations in deep wells raises significant safety concerns. It is vitally important during fracing operations to have an understanding of the pressure downhole. In fracing, the objective is to inject high pressure fluid into the formation with the pressure being so great as to overcome the weight of overburden and pore pressure to cause the created fractures to widen. To maintain the fractures, a proppant, such as sand, is included in the fracing slurry and is flowed into the fractures to keep them open. The greater the degree of fracture that is achieved, the greater the flow of hydrocarbons out of the formation and into the wellbore. Thus, during the fracing operation, high pressure fluids and proppants are pumped downhole, out of the workstring, through the perforations and into the fracture. The proppant flows into the created fractures and begins filling the fractures from the outermost region back towards the wellbore. Once the proppant essentially fills the fractures back to the wellbore, and with fracing fluid continuing to be pumped downhole, the downhole pressure increases suddenly and dramatically. This condition is referred to as “screen out.” Screen out is essentially when the formation will no longer accept more fracing fluid or proppant. When screen out occurs without warning, a potentially hazardous condition is created at the surface where the fracing fluid is continuing to be pumped through the work string at very high pressures, such as from 5,000 to 18,000 psi. When the downhole pressure suddenly spikes, the differential pressure as measured across the wall of the work string at the surface may exceed the margin of safety causing the pipe to burst, subjecting personnel and equipment to risk. It is thus extremely important to know when a screen out condition is imminent so that the pumps can be turned off or throttled back before the situation becomes dangerous.  
       [0022] Positioning a pressure sensor in the workstring adjacent to the discharge sub to sense downhole pressure and communicate the pressure data to the operator or controller at the surface would be advantageous; however, communicating data to the surface during fracing operations has presented a problem. Although it is common to use mud pulse telemetry in well operations for transmitting data to a surface controller, mud pulse telemetry is difficult if not impossible to employ in fracing operations because there is too much hydrostatic noise which prevents transmission of telemetry up the annulus to the surface. Further, although electrical signals can be sent uphole via conductors strapped on the outside of the work string, the conductors are subjected to abuse and damage as the work string scraps against the sides of the well bore while the workstring is lowered into or removed from the bottom of the wellbore, and as well fluids flow around the conductors. The problems arising from the conductors being subjected to extreme physical abuse are magnified tremendously in deep well applications.  
       [0023] As a consequence of the inability to accurately transmit actual, real-time downhole pressure measurements to the surface, it is conventional in prior art fracing operations to attempt to calculate downhole pressure by considering a variety of parameters such as surface pressure. However, for several reasons, it is extremely difficult to extrapolate the downhole pressure from the measured surface pressure and the other available data, particularly in deep well operations.  
       [0024] The pressure measured at the surface is a combination of the friction pressure, the hydrostatic pressure and fracture gradient pressure. The gradient pressure may vary significantly depending on particular local conditions. A typical fracture gradient pressure is approximately 0.7 psi per foot of depth of well bore. Thus, in this example, at a depth of 3000 feet, the downhole pressure attributable to the fracture gradient will be approximately 2100 psi. Obviously, as the well extends deeper, the fracture gradient pressure increases. The other pressure components are not so easily quantified. In pumping the fracing fluid downhole, a large component of the pressure measured at the surface is the friction pressure created by the fluid moving at high velocities through a relatively small diameter pipe. In addition to the friction pressure, there exists a hydrostatic pressure in the flow bore of the work string caused by the weight of the column of fluid in the flow bore. However, the concentration of the proppant in the slurry is typically increased during the course of a fracing operation. Thus, the weight of fluid being pumped downhole increases as the process continues over time. As the density of the fluid changes during the fracturing job, the hydrostatic pressure and the friction pressure in the flow bore also change. These changing variables, coupled with the high volume of fluid that is pumped during the fracing operation, makes calculating the downhole pressure very complex. In deep wells, the friction pressure and hydrostatic pressure are so great that it masks the onset of the screen out condition. The fluids and their density change so fast that it is difficult if not impossible to calculate accurately downhole pressure. Once again, if the downhole pressure spikes quickly and the spike cannot be seen or predicted soon enough based on the pressures calculated at the surface, the excessive pressure can cause the work string to burst, endangering both crew and equipment. Thus, rather than extrapolating and relying on calculations based on changing variables, it would be much more desirable to have a means for accurately measuring downhole pressure and communicating that measurement to the surface in real time to enable appropriate decision making.  
       [0025] Also important to conducting a proper fracing job is to know the temperature downhole. This is because the fracing fluid will often be multi-phased, and it is important to the operation to know the percent of fluid in the gaseous phase and in the liquid phase. The respective liquid/gas percentages of the fluid are a function of the downhole temperature. If the temperature downhole were known and could be communicated accurately to the surface in real time, adjustments could be made to ensure that the appropriate and optimum fluids were being injected into the formation. The fact that the fracing fluid is in two phases and that the volume of gas changes continuously as the fluid moves down into the well bore also makes it even more difficult to calculate bottom hole pressure.  
       [0026] It is also desirable in fracing operations to determine the size, orientation and shape of the fracture being created so that the operation can be ceased or altered if the fracture propagates in a manner that is undesirable. Presently, it is known to convey tilt sensors downhole via a wireline, and to attach the sensors magnetically to the casing wall at various locations along or adjacent to the interval being treated. In what are referred to as “mini fracing” operations, that is, when pumping fluid but not proppant, tilt sensors are capable of detecting the tilt in the casing that results from the pumping operation and communicating the sensed data to the surface via the wire line&#39;s conductors. Unfortunately, when the fracing operation includes pumping proppant downhole, this prior method of employing a wire line communication link is not believed to be viable because of erosion to the conductors that occurs at the well head where the proppant is injected, and because of the danger of proppant building-up around the downhole tilt sensors which might cause the downhole assembly to become stuck. Nevertheless, because of the significant benefits to be derived from such data, a means for measuring the tilt and communicating the sensed value in real time to the surface in a proppant fracing operation would be highly desirable.  
       [0027] As can be readily seen from the foregoing, it is advantageous to provide improved well treatment and proppant fracturing apparatus and methods which eliminate or at least substantially reduce the above-mentioned problems, limitations and disadvantages commonly associated with the previous stimulation techniques generally described above. It is accordingly an object of the present invention to provide such improved apparatus and methods.  
       SUMMARY OF PREFERRED EMBODIMENTS OF THE INVENTION  
       [0028] Accordingly, there is provided herein apparatus and methods enabling multiple zones within a formation to be treated sequentially with a single trip of the work string and which, in certain embodiments, provide transmission of power and transmission of data indicative of actual wellbore conditions for enhanced safety and system reliability.  
       [0029] A preferred apparatus includes a bottom hole assembly having a tubular, ported sub and a tubing string connected to the bottom hole assembly. The tubing string and bottom hole assembly include fluid passageways that are in fluid communication so that treatment fluids may be pumped from the surface through the tubing string and out of the ports in the tubular sub when positioned adjacent to the zone to be treated. Preferably, the tubing string is a composite tubing having conductors embedded in the walls of the tubing and extending from the bottom hole assembly to the surface. Alternatively, metal tubing or jointed pipe may be employed with an umbilical of electrical conductors supported by the tubing or pipe, the conductors again extending from the bottom hole assembly to the surface.  
       [0030] It is preferred that the bottom hole assembly include at least one sensor for measuring wellbore parameters and communicating in real time the sensed data to the surface controller, with the sensor being coupled to the surface controller via the conductors supported by the tubing. The conductors may include electrical conductors, fiber optics conductors or others.  
       [0031] To isolate the appropriate well interval to be treated, it is preferred that the bottom hole assembly include one or more packers and a packer actuator associated with each packer for causing the packer to expand and isolate a well interval in response to an electrical signal transmitted from the surface to the bottom hole assembly via the conductors. The conductors supported by the tubing string provide two way communication between the surface and the bottom hole assembly, as well as a means for transmitting electrical power from the surface to the bottom hole assembly. Further, given this direct communication link from the bottom hole assembly to the surface, real time well data may be sensed and communicated to the surface controller enabling adjustments to the treatment operation to be performed, both to enhance the effectiveness of the operation and to provide a means to determine downhole conditions accurately, such as pressure, and, when required, to throttle back or shut down pumping equipment before any dangerous situation develops.  
       [0032] In another preferred apparatus, the bottomhole assembly includes a detector sub having a sensor that detects anomalies in the casing, such as perforations and casing joints. Such a detector communicates the sensed data to the surface via the conductors supported by the tubing string so that the bottom hole assembly can be appropriately positioned. More specifically, the detector permits the packers to be set in blank sections of casing so as to properly isolate a particular well interval so that the fluids pumped downhole can penetrate into the intended zone via the perforations, and so that the packers are not eroded or washed out due to improper packer placement within a casing anomaly.  
       [0033] A preferred method is disclosed and includes placing a tubing string with a bottom hole assembly having a ported sub and a plurality of sequentially settable packers into a wellbore, locating a blank segment of casing above the first producing zone, setting a first packer in that blank region of casing to isolate a first well interval, pumping treatment fluid through the ported sub from the surface and into the first isolated interval, and sensing at least one downhole parameter and communicating the sensed parameter to the surface via conductors extending along the tubing string. The method may also include stopping the flow of treatment fluid when the sensed parameter meets a predetermined criteria, such as when a downhole pressure is sensed that indicates that a “screen out” condition is about to occur, or when downhole tilt meters indicate that a fracture is propagating in an unanticipated or undesirable manner.  
       [0034] The disclosed methods also include raising the bottom hole assembly to a position above the first set packer, locating a blank segment of casing above the depth of the next producing zone, setting a second packer in that blank region of casing to isolate a second well interval, pumping treatment fluid through the ported sub and into the second isolated interval, and sensing at least one downhole parameter and communicating the sensed parameter to the surface via conductors.  
       [0035] The preferred embodiments summarized above thus permit multiple zones within a given formation to be treated sequentially, with a single trip of the well treatment work string. Given the real time communication link provided via conductors, either embedded in the wall of the tubing string or supported by other means along the length of the tubing or pipe, real time communications of important downhole conditions can be communicated to the surface, enabling the surface controller and operator to avoid dangerous conditions and better tailor the treatment operation, such as by varying the density or makeup of the fluid being pumped downhole.  
       [0036] Thus, the embodiments of the invention summarized above comprise a combination of features and advantages which enable them to overcome various problems of prior devices systems and methods. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description of the preferred embodiments of the invention, and by referring to the accompanying drawings. 
     
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
     [0037] For a more detailed description of the preferred embodiments of the present invention, reference will now be made to the accompanying drawings, wherein:  
     [0038]FIG. 1 is a schematic elevation view, partly in cross section, of a preferred embodiment of the well treatment apparatus the present invention disposed in a subterranean well.  
     [0039]FIG. 2 is a cross sectional view of a work string including composite continuous tubing for the apparatus shown in FIG. 1.  
     [0040]FIG. 3 is a cross sectional view of the composite tubing shown in FIGS. 1 and 2, the section taken along the longitudinal axis of the tubing.  
     [0041]FIG. 4 is an enlarged view of a bottom hole assembly of the well treatment apparatus shown in FIG. 1.  
     [0042]FIG. 5 is a schematic elevation view, partly in cross section, of a portion of the bottom hole assembly shown in FIG. 4.  
     [0043]FIG. 6 is a schematic elevation view, partly in cross section, of a hydraulic distribution sub in the bottom hole assembly shown in FIG. 4.  
     [0044]FIG. 7 is a schematic view of the hydraulic circuit employed in the bottom hole assembly shown in FIG. 4.  
     [0045]FIG. 8 is a schematic elevation view, partly in cross section, of the sensor sub and stinger of the bottom hole assembly of FIG. 4.  
     [0046]FIG. 9 is a functional block diagram of the electric power and control system for the well treatment apparatus shown in FIG. 1.  
     [0047] FIGS.  10 A- 10 D are schematic elevation views, partly in cross section, of a well including producing zones which are to be treated using the system and apparatus of FIG. 1, the figure showing the bottom hole assembly in various positions as it conducts sequential operations on the individual zones.  
     [0048]FIGS. 11A, 11B are schematic elevation views, partly in cross section, of another preferred embodiment of the well treatment apparatus, the bottom hole assembly being shown in various positions in the well bore as it is used to sequentially treat various zones.  
     [0049]FIG. 12 is a schematic elevation view, partly in cross section of a portion of the embodiment of FIG. 4 employing propellant-activated packers.  
     [0050]FIG. 13 is a schematic elevation view, partly in cross section, of still another preferred embodiment of the well treatment apparatus.  
     [0051]FIG. 14 is a schematic elevation view, partly in cross section, of still another preferred embodiment of the well treatment apparatus. 
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS  
     [0052] The present invention relates to methods and apparatus for well treatment such as fracing or stimulation operations. The present invention is susceptible to embodiments of different forms. There are shown in the drawings, and herein will be described in detail, specific embodiments of the present invention with the understanding that this disclosure is to be considered an exemplification of the principles of the invention, and is not intended to limit the invention to that illustrated and described herein. Further, it is to be fully recognized that the different teachings of the embodiments discussed below may be employed separately or in any suitable combination to produce desired results.  
     [0053] In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . ”. Also, the terms “couple,” “couples” and “coupled” is intended to mean and refer to either an indirect or a direct electrical connection. Thus, for example, if a first device “couples” or is “coupled” to a second device, that interconnection may be through a direct electrical connection of the two devices, or through an indirect electrical connection via other devices, conductors and connections. Further, reference to “up” or “down” are made for purposes of ease of description with “up” meaning towards the surface of the wellbore and “down” meaning towards the bottom of the wellbore. In addition, in the discussion and claims that follow, it is sometimes stated that certain components or elements are in “fluid communication.” By this it is meant that the components are constructed and interrelated such that a fluid could be communicated between them, as via a passageway, tube or conduit.  
     [0054] Referring now to FIG. 1, there is shown a preferred embodiment of the present invention including a surface operating system  50 , a work string of composite coiled tubing  100 , and a bottom hole assembly (BHA)  200 . Operating system  50  is positioned at the surface adjacent to well  12  and generally includes a well head  14  disposed atop of a well bore  18  that extends downwardly into an earthen formation  20 . Borehole  18  extends from surface  16  to borehole bottom  30  and includes casing  22  extending therebetween. In the example shown, wellbore  18  includes at least one interval  32  containing three, spaced apart zones  34 - 36  that are believed to contain hydrocarbons that can be economically recovered. Hereinafter, such zones may sometimes be referred to as “producing zones”  34 - 36 . It should be appreciated that this well environment is described for explanatory purposes, and that the present invention is not limited to the particular borehole thus described, it being appreciated that the present invention may be used in a variety of well bores. In particular, although the wellbore  18  is shown vertical, the wellbore may be a deviated wellbore and may further include a horizontal portion. BHA  200  is attached to the lower most end of coiled tubing  100 . Coiled tubing  100  and BHA  200  make up a well treatment assembly  40  that is injected into and retrieved from borehole  18  by operating system  50 .  
     [0055] Surface operating system  50  includes a power supply  52 , a surface controller  54 , a coiled tubing spool  56  and a tubing injector head unit  58 . Injector head  58  feeds and directs coiled tubing  100  from the spool  56  into the well  12 . Although the coiled tubing  100  is preferably composite coiled tubing hereinafter described, it should be appreciated that the present invention is not limited to composite coiled tubing and in certain embodiments, may be steel coiled tubing with an electrical umbilical mounted on or within the steel coiled tubing. See for example, U.S. Pat. No. 5,920,032, hereby incorporated herein by reference. Certain embodiments may likewise be practiced using jointed metal pipe, rather than continuous metal or composite coiled tubing as discussed below.  
     [0056] Referring still to FIG. 1, tubing spool  56  feeds composite tubing  100  over guide  60  and through injector head  58  and stripper  62 . The composite coiled tubing  100  is injected through blowout preventer  64  and into well  12  by injector head  58 , the tubing  100  forming an annulus  24  with the casing  22 . The composite coiled tubing  100  preferably includes conductors  144  embedded in the wall of tubing  100 , as hereinafter described and best shown in FIGS. 2 and 3. Electrical conductors  66 , 68  electrically couple power supply  52  with the electrical conductors  144  in the wall of composite coiled tubing  100 . Similarly, conductors  70 ,  72  couple controller  54  with the electrical conductors  144  in composite coiled tubing  100 . It should be appreciated that, in this embodiment, both data and electrical power are transmitted through the electrical conductors  144 . These conductors  144  extend along the entire length of composite coiled tubing  100  and are coupled to various components in BHA  200 , as hereinafter described.  
     [0057] Composite coiled tubing  100  is best described with reference to FIGS. 2 and 3. Coiled tubing  100  is similar to composite coiled tubing described in U.S. Pat. Nos. 6,246,066; 6,257,332; and U.S. patent application Serial No. 60/353,654 filed Feb. 1, 2002, the entire disclosure of each being hereby incorporated herein by reference. Coiled tubing  100  preferably has an inner impermeable fluid liner  132 , a plurality of load carrying layers  134  (only exemplary layers being shown), and at least one wear layer  138 . As best shown in FIG. 3, a plurality of conductors  144  are embedded in the wall of the tubing and are preferably embedded between the load carrying layers  134  and the inner liner  132 . Conductors  144  includes conductors for conducting power and data as described more fully below.  
     [0058] Referring still to FIGS. 2 and 3, load carrying layers  134  are preferably formed of a resin and fiber and energized to provide the required tensile strength and burst strength to sustain the load of the well treatment assembly  40  suspended in fluid, including the weight of the composite coiled tubing  100  and bottom hole assembly  200 , and to sustain the differential pressure placed on the tubing  100  by internal and external fluid pressures. The fibers of load carrying layers  134  are preferably wound into a thermal setting or curable resin. Carbon fibers are preferred because of their strength. Although glass fibers are not as strong, glass fibers are much less expensive than carbon fibers and may also be employed. Further, a hybrid of carbon and glass fibers may be used for load carrying layers  134 . Thus, the particular fibers for the load carrying layers  134  will depend upon the well, particularly the depth of the well, such that an appropriate compromise of strength and cost may be achieved in the fibers selected. Typically, an all carbon fiber is preferred for layers  134  because of its strength and its ability to withstand pressure.  
     [0059] The load carrying layers  134  are engineered so as to provide the composite coiled tubing  100  with various mechanical properties including tensile and compressive strength, burst strength, flexibility, resistance to caustic fluids, gas invasion, external hydrostatic pressure, internal fluid pressure, ability to be stripped into the borehole, density i.e. flotation, fatigue resistance and other mechanical properties. Layers  134  are wrapped and braided to maximize the mechanical properties of composite coiled tubing  100 , adding substantially to its strength.  
     [0060] The impermeable fluid liner  132  is an inner tube preferably made of a polymer, such as polyvinyl chloride or polyethylene or PDVF. Liner  132  can also be made of a nylon, other special polymer, or elastomer. In selecting an appropriate material for fluid liner  132 , consideration is given to the chemicals in the fluids to be used in performing the well treatment operations in zones  34 - 36  and the temperatures that are to be encountered downhole. The primary purpose for inner liner  132  is to serve as an impermeable fluid barrier since carbon fibers of load carrying layers  134  are not impervious to fluid migration, particularly after they have been bent. The inner liner  132  is impermeable to fluids and thereby isolates the load carrying layers  134  from the fluids that are conducted through the flow bore  146  of liner  132 . Inner liner  132  also serves as a mandrel for the application of the load carrying layers  134  and the other layers during the manufacturing process for the composite coiled tubing  100 .  
     [0061] A wear layer  138  is preferably braided around the outermost load carrying layer  134 . The wear layer  138  is a sacrificial layer since it will engage the inner wall of the borehole  18  and will be subjected to wear as the composite coiled tubing  100  is tripped into the well  12 . Wear layer  138  protects the underlying load carrying layers  134 . One preferred material for wear layer  138  is Kevlar™ which is a very strong material that is resistant to abrasion. It may be desirable to employ multiple wear layers. For example, a wear indicator layer  136  may be provided between the outermost load carrying layers  134  and wear layer  138 . One advantage of providing wear indicator layer  136  is that it can be of a different fiber and color relative to wear layer  138 , making it easy to determine the wear locations on composite coiled tubing  100 . The wear indicator layer  136  is for convenience and is not essential to the tubing  100 . Wear layer  136 , may be made of glass fibers, such as fiberglass. It should be appreciated that, in certain applications, inner liner  132  and wear layers  136 ,  138  may not be critical to the use of composite coiled tubing  100  and may not be required.  
     [0062] Another impermeable fluid layer  137  is preferably provided to serve as another impermeable layer to liquids and gases. Outer layer  137  is preferably made of a polymer, such as polyvinyl chloride or polyethylene or PDVF, and provides an outer impermeable layer to resist negative permeability. Negative permeability occurs when there is a higher pressure in the annulus  24  then in the flowbore  146 , i.e. the differential pressure is greater towards the flowbore  146 .  
     [0063] The composite tubing  100  is engineered in accordance with the preferred characteristics previously described and for the particular application of the tubing. The tubing has a ratio of carbon fiber to the matrix holding the fiber together. Each layer of fiber is wrapped at a predetermined angle which typically is varied between the layers  134 . The layers of carbon fiber are wrapped around liner  132  in a prescribed angle. Layers  134  can be added or subtracted, and by adding more or less fiberglass, the weight of the composite coiled tubing can be controlled. For example fiberglass may be substituted for carbon fiber which is lighter than the fiberglass. The fiberglass includes layers of glass fibers which typically make the composite coiled tubing heavier. Thus the composite coiled tubing may be made to be substantially neutrally buoyant allowing the composite coiled tubing to float in the borehole fluids.  
     [0064] During the braiding process, conductors  144 , which may include electrical conductors, data transmission conductors, sensors and other data links, are embedded within coiled tubing  100 , preferably between the load carrying layers  134  and inner liner  132 . These conductors  144  are wound into and become encased within the wall of composite coiled tubing  100 . It should be appreciated that any number of electrical conductors, data transmission conduits, and sensors may be embedded as desired in the wall of composite coiled tubing  100 . As shown in FIGS. 2 and 3, the conductors  144  are preferably disposed about the liner  132  in a layer of fiberglass  147 . The principal function of fiberglass layer  147  is to contain the conductors  144  and to provide a continuous circumferential outer surface upon which load carrying layers  134  can be disposed. The fiberglass  147  serves as a filler between the conductors  144 . The conductors  144  are first wrapped around the liner  132  and then the fiberglass  147  is applied. Disposed around the layer of fiberglass  147  and conductors  144  are the multiple load carrying layers  134 .  
     [0065] Coiled tubing  100  may include a myriad of conductor types. For example, coiled tubing  100  may include one or more fiber optic cables; mono-cables (consisting of an insulated copper core conductor having a ground shield disposed about the insulated core); multi-conductor cables; single conductors (solid or braided wire); flat ribbon conductors and coaxial cables. In the embodiment of FIGS. 2, 3, for example, there are shown six single cooper conductors  144  (i.e., three pairs of conductors), which transmit both power and data. However, including other types of conductors embedded within composite tubing  100  may be desirable for providing power or data between the surface and bottom hole assembly  200  as may be useful for equipment or applications beyond those described specifically with reference to the present embodiments of the invention.  
     [0066] In the embodiment shown in FIGS. 2, 3, the conductors  144  used for power transmission from the power supply  52  at the surface to the bottom hole assembly  200  is preferably one pair of individual copper wires  144 . Such conductors allow the transmission of a large amount of electrical power from the surface to the bottom hole assembly  200 . One cooper wire  144  serves as a high potential conductor, with the other being the return or ground. For transmitting the power necessary for a deep well application of the embodiment of the invention now being discussed, it is preferred that cooper wire  144  be approximately 24-18 gauge. Copper wire  144  may conduct at high voltages, such as 400 volts. Further, by employing multiplexing techniques, there is provided a two-way communication or data transmission through conductors  144 . In this embodiment, two additional pairs of wires  144  are provided for redundancy in the event that a first pair becomes damaged.  
     [0067] As discussed above, data and communication signals may be multiplexed and conducted via power-conducting cooper conductors  144 ; however, in some applications it may be preferred that the data and communication signals be sent via separate conductors, such as by fiber optic cable or by one or more pairs of conductors within a multi-conductor cable. Where provided, in composite tubing  100 , a multiconductor cable includes a plurality of separately insulated conductors, preferably about 24-18 gauge, enclosed in a further layer of insulation. Alternatively, data and communications can be transmitted between BHA  200  and the surface via fiber optics, such as via a fiber optic cable, or via a mono cable. In each case, such conductors constitute a high speed data link carrying communications from downhole to the surface such that it is transmitted to the surface in real time.  
     [0068] Sensors may also be embedded within the load carrying layers  134  and coupled to one or more of the data transmission conductors such as conductors  144 . As an alternative to embedded sensors, a fiber optic cable may itself be etched at various intervals along its length and disposed in composite coiled tubing  100  to serve as a sensor at predetermined locations along the length of composite coiled tubing  100 . This allows the parameters, in particular, temperatures, to be monitored along the length of composite coiled tubing  100  and transmitted to controller  54  at the surface.  
     [0069] Composite coiled tubing  100  may be made of various diameters. Although 1¼″-2″ are typical diameters for metal coiled tubing, composite coiled tubing  100  preferably has a diameter greater than 2 inches. The size of coiled tubing  100 , of course, will be determined by the particular application and well for which it is to be used.  
     [0070] Composite coiled tubing  100  has all of the properties requisite to enable the stimulation of deep wells. In particular, composite coiled tubing  100  has good longevity and, as compared to ferrous materials, has great strength for its weight when suspended in fluid. Composite coiled tubing  100  also is compatible with the fluids that are used to treat the producing zones, and approaches buoyancy (dependent upon weight and density of the treatment fluid) upon passing fluids down its flowbore  146  and back up the annulus  24 . This reduces to acceptable limits drag and other friction factors previously encountered by metal pipe. Since the composite coiled tubing  100  is not rotated during insertion or during the treatment operation, little torque is placed on composite coiled tubing  100 .  
     [0071] Although it is possible that the composite coiled tubing  100  may have any continuous length, such as up to 25,000 feet, it is preferred that the composite coiled tubing  100  be manufactured in shorter lengths such as, for example, in 1,000, 5,000, and 10,000 foot lengths. In deep well operations, it is typical to require multiple spools  56  of composite coiled tubing  100 . These additional spools, of course, are used to add to the length of the composite coiled tubing  100 . With respect to the diameters and weight of the composite coiled tubing  100 , there is no practical limitation as to its length. The various lengths of coiled tubing  100  are added serially together to form one continuous length and are connected together. As shown in FIG. 1, adjacent lengths  75 ,  76  of tubing are interconnected by connector  78  so as to form continuous coiled tubing  100 . A detailed description of the connector  78  is set forth in U.S. patent application Ser. No. 09/534,685, filed Mar. 24, 2000, hereby incorporated herein by reference. For electrical conductors in tubing, see U.S. Pat. No. 5,146,982, hereby incorporated herein by reference. Other types of connectors are shown in U.S. Pat. Nos. 4,844,516 and 5,332,049, both hereby incorporated herein by reference.  
     [0072] Referring now to FIG. 4, bottom hole assembly (BHA)  200  generally includes a plurality of series-connected BHA components  201 , a mandrel or stinger  210  extending downwardly from the BHA component series  201 , and a plurality of isolation packers  220  disposed about stinger  210 . Each packer  220  includes an interconnected valve sub  222  at its uppermost end that, in turn, is connected via one or more shear pins (not shown) to the packer  220  immediately above.  
     [0073] The uppermost sub of BHA component series  201  is an end connector sub  202  for releaseably connecting composite coiled tubing  100  to BHA  200 . Connector sub  202  can be any releasable connection capable of interconnecting a composite coiled tubing to a bottom hole assembly and providing the releasable connections for electrical and data connections and the flow of fluids that are pumped downhole. One such connector sub particularly useful for this embodiment of the invention is disclosed in U.S. Ser. No. 09/998,125 entitled Downhole Assembly Releasable Connection, filed Nov. 30, 2001, the entire disclosure which is hereby incorporated herein by reference. As described in Ser. No. 09/998,125, connector sub  202  includes a “fishing neck” allowing BHA to be retrieved with minimal cost and inconvenience should BHA  200  become stuck in the well or it otherwise be necessarily to disconnect composite tubing  100  from BHA  200  and to retrieve BHA  200  at a later time.  
     [0074] BHA component series  201  further includes supervisory sub  203 , hydraulic distribution sub  204 , gamma tool  205 , detector assembly  207 , power distribution sub  208 , and sensor sub  209 , tilt sensor subs  290 , described in more detailed below. A common flowbore  211  extends throughout the BHA component series  201 .  
     [0075] As shown in FIGS.  4 - 5 , flowbore  211  in stinger  210  is in fluid communication with central bore  146  of composite tubing  100 . The stinger  210  includes near its lower end, a plurality of discharge ports  212  that are provided to convey treatment fluids from common flowbore  211 , through the perforations  37 - 39  and into producing zones  34 - 36 . The stacked series of isolation packers  220  with valve subs  222  are mounted on stinger  210 . Six packers  220   a - f  are shown in FIG. 4, it being understood that more or fewer than this number of packers will be employed depending upon, among other factors, the number of zones to be treated in a single trip of BHA  200 . The lower most end of each packer  220  includes an engaging surface for engaging spring loaded latch members  320  of collet  330  that is disposed about stinger  210  as best shown in FIG. 8. Referring momentarily to FIG. 8, each latch member  320  is spring biased radially outward by spring  322  housed within stinger  210  and includes a camming surface  324  at its uppermost surface. As shown in FIGS. 4 and 8, stinger  210  is latched initially into the engaging surface of lowermost packer  220   a . A stop member  326  (FIG. 4) is attached to stinger  210  above the uppermost packer  220   f  to prevent packers  220   a - f  from being forced upward and against BHA component series  201  during injection of well treatment assembly  40  into the borehole or during well treatment operations.  
     [0076] Packers  220  may be any conventional annulus sealing assembly known to those skilled in the art for use in packing off or sealing one section of the annulus from another. In this instance, the packer believed most useful is one that is inflated or actuated by pressurized hydraulic fluid and that radially expands in order to seal between stinger  210  and the wall of casing  22 . Each packer  220  includes a pair of mechanical slips (not shown) that, once actuated, cause the packer to expand radially outward. A packer  220  useful in this application includes that disclosed in U.S. patent application Ser. No. 10/116,572 filed Apr. 4, 2002 entitled “Multiple Zones Frac Tool” the entire disclosure of which is hereby incorporated herein by reference. Packer  220  includes a valve sub  222  having a spring-actuated flapper member  223 , such a valve sub also being described in application Ser. No. 10/116,572. Additional valve subs  222  suitable for adaptation and use in the present embodiment include those shown in U.S. Pat. Nos. 6,152,232, and 4,825,902, hereby incorporated herein by reference. The material used to construct valve sub  222  preferably is a composite material that can be drilled out and thus easily removed after the well treatment process is complete.  
     [0077] Referring more particularly to FIG. 5, the wall of stinger  210  houses hydraulic actuators  240  for actuating packers  220 . Each actuator  240  is associated with one packer  220  and is connected to a conduit  242  for conducting pressurized hydraulic fluid from hydraulic distribution sub  204  to actuator  240 . Actuator  240  is controlled by actuation of connected solenoid valve  244 . Each solenoid valve  244  is associated with one actuator  240  and is coupled electrically to supervisory sub  203  (FIG. 4) by conductors  246  disposed in passageway or conduit  248  in the wall of stinger  210 .  
     [0078] The treatment operations enabled by this embodiment are, in part, carried out by means of a self contained hydraulic power system in bottom hole assembly  200 , the major components of which are housed in hydraulic distribution sub  204 . In total, the hydraulic system is best understood with reference to FIGS.  4 - 7 . Referring now to FIG. 6, hydraulic distribution sub  204  generally includes hydraulic fluid reservoir  230 , hydraulic pump  232  and electric motor  234 , along with conventional hydraulic piping extending the length of sub  204  and into stinger  210  where it interconnects with conduits  242 , shown in FIG. 5 for providing pressurized hydraulic fluid for actuating individual packers  220 , as described in more detail below.  
     [0079] Referring now to FIGS.  6 - 7 , hydraulic reservoir  230  contains hydraulic fluid and is connected to hydraulic pump  232  via suction line  231  and to a hydraulic fluid return line  233 . Hydraulic pump  232  is a conventional hydraulic pump and is coupled to electric motor  234  through a mechanical coupling  235  such that rotation of electric motor  234  causes hydraulic pump shaft to drive the pump. The output of pump  232  is connected to the supply line  236  for supplying hydraulic pressurized fluid to packer actuators  240   a - f.    
     [0080] A schematic diagram of the hydraulic distribution system is shown in FIG. 7. Referring to FIGS. 7 and 9, hydraulic supply line  236  is connected to the discharge end of hydraulic pump  232 , and return line  233  is connected to the hydraulic reservoir  230 . Each solenoid valve  244   a - f  is connected to both the hydraulic supply line  236  and the return line  233  to control the flow of pressurized hydraulic fluid to actuators  240   a - f . Control wires  246  couple each solenoid valve  244  to controller  354  (FIG. 9) in supervisory module  203  (FIG. 9). Power is supplied to the electric motor  234  via a power distribution module  381  located in power sub  208  (FIG. 9). Motor  234  drives pump  232  causing the pump to supply hydraulic fluid under pressure to the various hydraulic components. Selectively, controller  354  in supervisory module  203  (FIG. 9) sends an electrical signal via conductors  246   f  to open solenoid  244   f , for example, causing pressurized hydraulic fluid to energize actuator  240   f  which, in turn, actuates packer  240   f  to expand and engage the wall of casing  22 . In this embodiment, once actuated, each packer  220   a - f  remains in its extended or “set” position.  
     [0081] Referring once again to FIG. 4, BHA  200  also includes a detector assembly sub  207  used to locate anomalies in casing  22 , such anomalies including perforations  37 - 39 , and the casing joints in casing  22 . Detector assembly sub  207  is best described in U.S. patent application Ser. No. 09/286,362 entitled Casing Joint Locator Methods and Apparatus, and U.S. patent application Ser. No. 10/121,399 filed Mar. 12, 2002 entitled Magnetically Activated Well Tool the entire disclosure of which is hereby incorporated herein by reference.  
     [0082] Detector assembly sub  207  includes one or more sensors (not shown) for detecting, identifying and locating anomalies in steel metal casing  22 . Detector assembly sub  207  is used to locate and determine the depth of the anomaly, the depth being the distance between the anomaly and the surface measured through the bore of the casing string  22 . The detector sub  207  may further determine the angular orientation of the anomaly, such as a perforation, within the cylindrical wall of the casing  22 . In the vertical casing string, the angular orientation will be the azimuth of the anomaly. Detector sub  207  senses an increase or decrease in the mass of the casing wall  22  and a particular point, as well as sensing the absence of mass. Anomalies, including perforations and casing joints, form fringe effects which cause perturbations in the naturally-induced magnetic field of the casing  22 . The variation of the mass and/or the fringe effects alter the external magnetic field around the sensors in the sensor sub  207  causing an increase or decrease in the resistance of the sensor and thereby altering the flow of current through the sensor. A signal is generated in detector sub  207  by the change in current flow and is transmitted to the surface to provide a detection, identification, or location of the anomaly in the casing  22 .  
     [0083] Referring to FIGS. 4 and 9, detector assembly sub  207  includes an outer enclosure or pressure barrel  301  constructed of a non-magnetic material such a beryllium cooper. The pressure barrel  301  is constructed to be resistant to fluids and is capable of withstanding downhole pressures without collapsing. Detector assembly  207  further includes a sensor  302  which preferably is a “giant magnetoresistive” or GMR magnetic field sensor housed in pressure barrel  301 .  
     [0084] By way of background, giant magnetoresistive or GMR magnetic field sensors are know for use in high accuracy compasses and geophysical applications such as magnetic field anomaly detection in the earth&#39;s crust. GMR sensors are constructed from alternating, ultrathin layers of magnetic and non-magnetic materials. GMR sensors provide high sensitivity to changes in a nearby or surrounding magnetic field. GMR sensors of this type are described in the brochure entitled “NVE—Nonvolatile Electronics, Inc. The GMR Specialists” with errata sheets, and are currently manufactured and marketed by Nonvolatile Electronics, Inc., 11409 Valley View Road, Eden Prairie, Minn. 55344-3617, (612) 829-9217. The GMR sensor uses a “giant magnetoresistive effect” to detect a change in electrical resistance that occurs when stacked layers of ferromagnetic and non-magnetic materials are exposed to a magnetic field.  
     [0085] The GMR sensor  302  is adapted to detect a change in a surrounding magnetic field and, in response thereto, generate a signal indicative of the change. The sensitivity of the GMR sensor permits detection of small anomalies in the surrounding magnetic structure, such as the perforations  37 - 39  and the discontinuities that exist between a pair of interconnected casing sections making up casing string  22 . It is noted that a GMR sensor  302  itself generates essentially no magnetic signature and, therefore, will not affect the operation of other downhole equipment that detect or rely upon magnetic readings.  
     [0086] The preferred sensor  302  is very small having typical dimensions of 0.154 inches by 0.193 inches by 0.054 inches. Thus, sensor  302  is sufficiently sensitive to detect perturbations of a similar size, i.e., substantially less than an inch. The advantages of the GMR sensor include reduced size, high signal level, high sensitivity, high temperature stability, and low power consumption.  
     [0087] Referring to FIG. 9, the detector assembly  207  also includes a signal processor  303  that is operably interconnected with the sensor  302 . The signal processor  303  receives the signal provided by the sensor  302 , amplifies the signal, and shapes it in order to provide a processed signal more recognizable. At the surface, in the preferred embodiment described here, the processed signal features a readily recognizable square wave, the high state portion of which corresponds to the presence of a casing joint or perforation. The signal processor  303  includes an amplifier and an analog-to-digital converter (neither shown), which are well-known components. The amplifier enhances the signal while the converter is used to convert the analog readings obtained by the sensor  302  into a more readily recognizable digital signal. If desired, the signal processor  303  may incorporate one or more noise filters of a type known in the art in order to remove noise from the signal generated by the sensor  302 . Other signal processing techniques used to enhance the quality of such signals may be applied.  
     [0088] The detector assembly  207  further includes a data transmitter  304  that is operably interconnected with the signal processor  303 . The data transmitter  304  receives the amplified and processed signal created by the signal processor  303  and transmits it supervisory module  203  to be processed and relayed to controller  54  located at the surface of the wellbore.  
     [0089] In operation, the sensor  302  senses the perturbation created by the increased or changed magnetic fields associated with anomalies in the wall of the casing string, such as the connections or joints between casing sections. The detector assembly  207  operates in the same manner to detect perforations  37 - 39  in the wall of the casing  22 . Perforations  37 - 39  are small, generally less than one inch in diameter, and typically having a diameter of between approximately 0.18 and 0.5 inches. Thus, perforations  37 - 39  have the same magnetic force qualities as gaps in casing joints. Due to the natural magnetic field of the casing  22 , the perforations produce fringe effects due to the lines of attractive magnetic forces across the sides of the perforations  37 - 39 . The attractive magnetic forces produce an increased magnetic signature just as with the joints in casing as discussed above. With a detector assembly  207  having a resolution high enough to detect the increased magnetic signatures of the perforations  37 - 39 , the exact location of the perforations can be determined.  
     [0090] For perforation patterns having perforations  37 - 39  on one side of the casing  22  in a given plane perpendicular to the longitudinal axis of the casing  22 , only one sensor  302  is needed. For perforation patterns with perforations  37 - 39  on more than one side of the casing  22  per plane, more than one sensor  207 , is needed to detect individual opposed perforations. However, with perforation patterns having perforations  37 - 39  on more than one side per plane, one sensor  302  may still be used to detect the perforation zone of the casing  22  because it is not necessary to detect the individual perforations  37 - 39 .  
     [0091] Bottom hole assembly  200  further includes gamma tool sub  205  useful for receiving gamma radiation from the surrounding formation and signaling to the surface controller  54  the sensed value. Those values, at the surface, can then be correlated via previously recorded data, to determine the location of bottom hole assembly  200 . Similarly, radioactive tags may be attached to the wall of casing  22  during well completion operations, and gamma tool  205  used to detect and transmit to surface controller  54  the identification and location of the tags. This, again, provides a means to determine the position and depth of BHA  200 . Gamma tool sub  205  may be any conventional tool well known to those skilled in the art for measuring gamma radiation given off by the formation.  
     [0092] Referring now to FIGS. 4 and 8, sensor sub  209  houses and protects various sensors used to collect downhole data and to transmit the sensed data to the surface controller  54  via conductors  144  in composite coiled tubing  100 . Although any of a variety and number of sensors may be employed, it is preferred that sensor sub  209  include at least a temperature sensor  250 , as well as various pressure sensors  254 ,  258 ,  262 , and load sensor  280 . Temperature sensor  250  may be, for example, a thermocouple having on a probe  251  for measuring temperature in the borehole annulus. The sensed temperature is then communicated via lead  271  to controller  354  in supervisory module  203 . An auxiliary or backup temperature sensor (not shown) is preferably provided as a backup in the event that temperature sensor  250  fails. Alternatively, both sensors may be provided with their outputs being averaged or otherwise considered by processor  354  in supervisory module  203 .  
     [0093] Sensor sub  209  in bottom hole assembly  200  includes a load sensor  280 . Load sensor  280  will sense both tension and compression on the bottom hole assembly  200 , and thus on coiled tubing string  100  and transmit a signal representative of the sensed value to controller  354  in supervisory module  203  via conductors  275 . Excessive tension or compression will indicate to the surface controller  54  that the well treatment assembly  40  is hung up in the borehole, necessitating that appropriate action be taken before well treatment assembly  40  becomes damaged. Load sensor  280  is also advantageous in indicating when a packer has failed. More specifically, as treatment fluid is pumped into an isolated interval, high pressure exerts an upward force on bottom hole assembly  200 . If a mechanical problem occurs with a packer  220 , such as when the packer  220  or bottom hole assembly  200  begins to move up hole because it is no longer stationary, the composite coiled tubing  100  could become damaged. Thus, load sensor  280  can be used to give the operator warning so that the pumps can be turned off or adjusted before damage occurs.  
     [0094] Referring to FIG. 4, BHA  200  includes a plurality of tilt sensor subs  290   a - c . Tilt sensor subs  290   a - c  are spaced apart along BHA component series  201  and are provided to sense the tilt or inclination of the casing at various locations so as to provide an indication to the surface controller  54  as to the extent and geometry of a fracture and the prorogation thereof. Tilt sensor subs  290   a - c  are of any conventional design and preferably include bubble type tilt meters that extend from the sub  290   a - c  and magnetically attach to the casing. Such tilt meters are known in the art and, for example, may comprise the apparatus and methods disclosed in U.S. Pat. No. 4,271,696, No. 4,353,244, No. 6,330,914 and No. 5,934,373, the disclosures of which are hereby incorporated by reference. Once the tilt meters are positioned on the casing wall and calibrated, the meter will provide an electrical signal representative of the tilt resulting from the well treatment operation. The electrical signal is communicated to supervisory module  203  via electrical conductors (not shown) within BHA  200 . The signal is thereafter communicated from controller  354  in module  203  to the surface controller  54  via conductors  144  in composite tubing  100 . Such data is evaluated by surface controller  54  to determine if and when certain conditions have occurred. For example, the data evaluation may determine that a fracture has propagated to an undesirable extent, indicating that the treatment process of a particular zone should be terminated.  
     [0095] Although the embodiments of the present invention may be used in a variety of well treatment operations, the following is an example of using these embodiments in a fracing operation. It should be appreciated that the descriptions relative to fracing are provided for illumination purposes only and should not be considered as limiting the present invention only to fracing operators. As previously explained with respect to well treatment in general, it is particularly important to understand the downhole pressure during fracing operations due to the high pressure fluid operation. In actuality, it is desirable to know various pressures. As shown in FIG. 8, pressure sensor  254  is connected via tube or conduit  255  to flow bore  211  such that the fluid pressure in the flow bore can be sensed during fracing operations. The pressure sensed in flow bore  211  at the upper end of stinger  210  will closely approximate the pressure in the isolated or “packed off” section of the well bore and will thus provide a pressure signal to the surface by which dangerous pressure spikes and screen out conditions can be anticipated. Pressure sensor  254  may be any standard pressure sensor such as a strain gage type or quartz crystal type. The output from pressure sensor  254  is communicated to controller  354  in supervisory module  203  via leads  272 . Supervisory module  203  thereafter communicates the sensed value to surface controller  54  via conductors  144  in coiled tubing  100 .  
     [0096] It is also desirable to know the differential pressure as measured across a packer  220 . Referring to FIG. 8, Packer  220   a  is shown in a “set” position sealing isolated annular interval  41  that is adjacent one of zones  34 - 36  from the upper annulus  24  extending above packer  220 . If such differential pressure exceeds that which packer  220   a  can withstand, the packer will fail and no longer isolate the interval  41  from the remainder of the annulus  24 , thereby rendering the fracing operation ineffective. Accordingly, it is desirable to provide a differential pressure sensor  262 . Pressure sensor  262  measures the pressure at the isolated annulus  41  adjacent the lower most portion of stinger  210  by means of conduit  263 . Sensor  262  is likewise coupled to the upper annulus  24  above packer  220  via conduit  264 . In a conventional manner, sensor  262  compares the two pressures from isolated annular interval  41  and upper annulus  24  and provides an output signal via leads  274  to controller  354  in supervisory module  203 . In turn, and as described more fully below, module  203  communicates the sensed differential pressure to the surface controller  54 . Pressure sensor  262  may be any conventional sensor for sensing differential pressures and providing a representative output.  
     [0097] It is also desirable to determine the pressure in upper annulus  24 . A rapid increase in pressure in upper annulus  24  sensed by pressure sensor  258  may indicate a packer failure or may instead indicate that the packer was improperly set within a perforated region of the casing  22  such that some of the fracing fluid injected into the interval believed to have been “isolated” is actually migrating back into the upper annulus  24  via the perforations that are above the location in which the packer was set. Accordingly, it is preferred that an upper annulus pressure sensor  258  be provided in sensor sub  209 . Sensor  258  senses the annulus pressure via conduit  259  and communicates a resulting output signal along leads  273  to supervisory module  203 . Pressure sensor  258  may be identical to sensor  254 .  
     [0098] As an alternative to the arrangement shown in FIG. 8, conduit  255 , shown associated with pressure sensor  254 , may connect with conduit  263  rather than to flowbore  211  so that the pressure sensed by pressure sensor  254  is the pressure of the isolated annulus  41  adjacent the lower most end of the stinger  210 . Likewise, sensors  258 ,  262  may share a single conduit to sense the pressure in upper annulus  24 , as opposed to having separate conduits  259 ,  264  as is shown in FIG. 8.  
     [0099] Still further, given the arrangement shown in FIG. 8, differential pressure sensor  262  may be eliminated with the differential pressure instead being calculated based on the signal received from annulus pressure sensor  258  and flow bore pressure sensor  254 , such calculation being made by processor  354  in supervisory module  203 . Because of the importance of collecting pressure data and the ability to communicate large amounts of data via conductors  144  in composite tubing  100 , it is believed generally preferable to have more pressure sensors, rather than fewer. Including pressure sensor  254 ,  258  and  262  can thus provide a measure of redundancy that is advantageous.  
     [0100] Referring now to FIG. 9, there is shown a schematic of the power and electronic control system  300  for the bottom hole assembly  200 . The system  300  includes a plurality of downhole sensors or data acquisition devices  352 , a plurality of control devices  358 , power distribution module  381 , detector module  207  and supervisory module  203 . As represented in FIG. 9, downhole data acquisition devices  352  include, for example, gamma tool sub  205 , temperature sensor  250 , pressure sensors  254 ,  258 ,  262 , load sensor  280  and tilt sensors  290   a - c . It should be appreciated that sensors  352  and control devices  358  may not only include the particular sensors and control devices described above, but other data collection and measurement sensors and control devices well know in the art.  
     [0101] Surface power supply  52  provides power to power distribution module  381  in power sub  208  through conductors  144  which, as previously described, are embedded within coiled tubing  1100  in this embodiment. Power distribution module  381  distributes power via a power bus  382  to supervisory module  203 , detector sub  207 , and the various other sensors  352  and control devices  358  in the bottom hole assembly  200 .  
     [0102] A “slow” data bus  376  provides a command and data communication path between controller  354  in supervisory sub  203  and power distribution module  381 , detector sub  207 , and the various sensors  352  and control devices  358 . Microcontrollers in each of the above components can communicate with each other via the slow bus  376 . A “high speed” data bus may also be provided between the supervisory module  203 , detector sub  207 , and other data acquisition devices such as sensors  352 . An example of a suitable high speed data bus may be a  1553  wireline data bus as is commonly used for wirelines.  
     [0103] The slow data bus  376  and high speed data bus  378  are coupled to supervisory module  203  which acts as a downhole controller for detector sub  207  and all downhole data acquisition devices  352  and control devices  358 . Supervisory module  203  is coupled to a transformer  388  by data leads  384 ,  386 . Leads  384 ,  386  are, in turn, coupled to conductors  144  embedded in coiled tubing  100  and extending to the surface. Conductors  144  are coupled to a second isolation transformer  390  in the surface operating system  50  at the surface. At the upper end of composite coiled tubing  100 , transformer  390  couples these conductors to a digital signal processor  392  housed within surface controller  54 . Transformers  388 ,  390  provide direct current isolation to protect uphole and downhole electronics from electrical faults.  
     [0104] The digital signal processor  392  in the surface controller  54  is a programmable device which serves as a modem (modulator/demodulator) at the surface. Likewise, controller  354  in supervisory module  203  includes a digital signal processor and modem. Digital signal processor  392  and controller  354  each preferably includes analog-to-digital conversion circuitry to convert received signals into digital form for subsequent processing.  
     [0105] Each downhole sensor  352  and control device  358  and detector sub  207  has a modem with a unique address from data busses  376 ,  378 . Thus, each modem may communicate individually and directly with the surface controller  54  using its unique address; however, it is preferred that each communicate with controller  354  in supervisory sub  203  and that, in turn, supervisory sub  203  communicate with surface controller  54 . Surface controller  54  can initiate communications with a particular device&#39;s modem by sending a message to the unique address. The modem in the receiving device responds by communicating an acknowledgment to the surface. This allows the surface to communicate with each of the downhole control devices  358  and sensors  352 . The downhole-surface communications preferably occur serially over conductors  144 . The command signals down to the power distribution module  381  directs the power to the appropriately designated downhole device.  
     [0106] Generally no signal is sent downhole requesting that the data from the sensors  352  or detector  207  be forwarded to the surface. Instead, it is preferred that data collected by the downhole devices be constantly communicated to the surface in a coded stream which can be read or ignored as desired by processor  392  in surface controller  54 . The high speed data bus  378  is normally reserved for data communications. All of this data is in digital form.  
     [0107] The commands from the surface to the downhole control devices  358  are preferably time- or frequency-multiplexed and sent downhole via conductors  144 . As previously mentioned, these communications may alternatively be sent downhole via conductors of other types that may be included in composite coiled tubing  100 . In their simplest form, the command may simply be on and off signals. The electrical power on power conductors  144  is preferably provided in the form of direct current.  
     [0108] Although a certain amount of data processing may occur downhole in some of the devices  358 , or in supervisory module  203 , it is preferred that the bulk of the data processing occur at the surface. Some of the data is initially conditioned downhole in module  203  prior to being forwarded to the surface. Each downhole control device  358  includes a microprocessor which acts as a controller. These microprocessors are normally not used for the processing of data. Such downhole processing is unnecessary since more than adequate bandwidth is provided to send all data to the surface for processing.  
     [0109] All of the downhole control devices  358  are electrically powered from the surface. Although some downhole control devices  358  may have hydraulic components, such components are preferably electrically controlled.  
     [0110] The supervisory module  203  serves as the controller for the bottom hole assembly  200 . The supervisory module  203  basically serves as a bus master and might be considered the hub of the downhole activity. It takes commands from the surface and retransmits them to the individual downhole devices. The supervisory module  203  also receives acknowledgements and data from the individual sensors  352  and detector sub  207  and retransmits them to the surface controller  54 . The commands and data are preferably provided in a frame format that allows the supervisory module  203  to efficiently multiplex and route the frames to the desired destination. The supervisory module  203  preferably transmits information to the surface using quadrature amplitude modulation (QAM), although other modulation schemes are also contemplated. Currently the QAM modulation provides a 65 kilobit per second transmission rate, but it is expected that transmission rates of 160 kilobits per second or greater can be achieved. The commands transmitted from the surface controller  54  to the supervisory module  203  are preferably sent using a frequency-shift keying (FSK) modulation scheme that supports a transmission rate of approximately 2400 baud. A QAM telemetry system useful for the embodiment of the invention now being described is disclosed in more detailed in U.S. patent application Ser. No. 09/599,343, filed Jun. 22, 2000 the entire disclosure of which is hereby incorporated herein by reference.  
     [0111] The surface processor  54  provides a way to “close the loop” between the sensors  352 , detector sub  207  and the downhole control devices  358 . The surface controller  54  can direct the downhole control devices  358  to perform an action and received sensed data indicative of the results. If the results are not what was expected, or if the data acquisition devices  352  indicate the need for a different action, then the surface controller  54  can direct the control devices  358  to adjust their actions accordingly. This form of feedback enables precise control and a fast response to changing conditions.  
     [0112] The data telemetry system described above provides many additional features and capabilities beyond those necessary solely to practice the embodiments of the well treatment apparatus and methods contemplated by the present invention. That is, more specifically, to practice the methods and use the apparatus described herein, data reflecting downhole conditions such as pressure, temperature, loading on the tubing and similar parameters is the preferred data needed to be transmitted uphole. That being the case, the more sophisticated QAM telemetry system described herein is not a requirement, the necessary data being capable of transmission up hole on a single pair of conductors via multiplexing techniques that are well known to those skilled in the art. The QAM telemetry system described herein is believed useful in that activation of other instrumentation and controls within bottom hole assembly  20  may be desirable.  
     [0113] Referring now to FIGS. 4 and 10A-D, in operation, zones  34 - 36  are treated in a single trip of well treatment assembly  40 , the zones being treated sequentially, starting with the lower most zone  36 . Thus, bottom hole assembly  200  is lowered into the borehole at surface  16  on coiled tubing  100  which is injected into the wellbore by means of tubing injector  58 . Referring to FIG. 10A, bottom hole assembly  200  is lowered to a depth where it is believed that ports  212  in stinger  210  are below the region of perforations  39  in zone  36 . Surface controller  54  activates detector assembly  207 . Tubing  100  and bottom hole assembly  200  are raised as detector assembly  207  detects, identifies and locates perforations  39  and the casing joints in casing  22 . Bottom hole assembly  220  is substantially rigid and the distance thus fixed between ports  212  and detector assembly  207 . Accordingly, when detector assembly  207  locates perforations  39  into zone  36 , the operator then directs controller  54  to raise bottom hole assembly  200  that known distance such that stinger ports  212  are substantially aligned with perforations  39 . Likewise, the distance between stinger ports  212  and the lower terminal end of packer  220   a  is a known distance such that bottom hole assembly  200  is raised still further until lower most packer  220   a  is above the perforations  39  in a “blank” section of pipe casing, meaning a section free of perforations and casing joints. Raising BHA  200  this additional distance also positions ports  212  above the uppermost performation  39  in interval  36 . Controller  54  receives signals from gamma tool  205  and compares that data with previously stored formation data or radioactive tags to verify that ports  212  in stinger  210  are appropriately positioned with respect to perforations  39 . Proper placement of packers in blank casing and ensuring that ports  212  are above the uppermost perforation  39  in the interval  36  is very important so as to prevent erosion or washout, and to reduce the possibility of a false indication that a screen out condition is occurring.  
     [0114] Once the position is confirmed, controller  54  sends the appropriate electrical signal to supervisory sub  203  to pack off the zone to be treated. Controller  354  in supervisory sub  203  causes solenoid valve  244   a  to actuate actuator  240   a  so that pressurized hydraulic fluid can actuate the slips in packer  220   a  thereby expanding packer  220   a  to engage the wall of casing  22  and thereby create an isolated, generally annular zone  41  that is packed off from upper annulus  24  by packer  220   a  as shown in FIG. 10A. As is known in the art, the outermost surface of packer  220   a  seals the wall of casing  22 , and the packer&#39;s seal bore seals with seals on the exterior of stinger  210 . With packer  220   a  set, stinger  210  is pulled upward slightly to sever a shear pin (not shown) thereby releasing packer  220   a  from stinger  210  and the remainder of the stack of packers  220 . This allows further adjustment to the location of stinger  210  within packer  220   a  so as to position ports  212  just above perforations  39 .  
     [0115] With BHA  200  properly positioned and interval  41  isolated, fracing fluid is then pumped through composite coiled tubing  100  and bore  211  of BHA  200  and stinger  210  where it exits ports  212  and passes into zone  36  through perforations  39 . As the proppant is injected in to the fracture, the bottom hole pressure increases. The pressure sensors  354 ,  358 ,  362  (FIG. 8) monitor the downhole pressure and continuously transmit signals to the controller  354  in supervisory sub  203 , which relays the sensed data to surface controller  54 . Likewise, tilt sensors  290   a - c  continuously monitor the orientation of the casing and, in real time, transmit data indicative of fracture geometry to surface controller  54  via supervisory sub  203 . By continuously monitoring the various pressures in the isolated interval  41  and, in particular, the rate of change in those pressures, the operator at the surface can determine when it is desirable or, for safety reasons necessary, to reduce or turn off the pumping operations or make other adjustments to the proppant slurry flow. Likewise, continuously monitoring temperature in the isolated interval  41  provides important information about the proppant slurry properties, enabling adjustments to be made to the composition and density of the slurry to optimize the fracing operation. Real time transmission of data from the tilt sensors  290  indicating fracture height, width and other geometries likewise provides valuable information as to how the reservoir is responding to treatment, and thereby enables better decision making with respect to the treatment process. The continuous monitoring of downhole parameters and the ability to communicate the sensed values to the surface in real time via conductors  144  in the tubing  100 , all as provided by the embodiment of the invention described above, permit accurate and precise control of the well treatment operation. These advantages provided by this embodiment thereby eliminate the necessity of having to rely on prior, less reliable techniques where downhole conditions had to be estimated or crudely calculated.  
     [0116] When it is determined that the appropriate volume of fluid and proppant has been injected into zone  36 , and before or immediately after screen out occurs, pumping of treatment fluid is ceased. The annulus  24  is then pressured up with water, brine or other suitable fluid, and bottom hole assembly  200  is raised such that stinger  210  is lifted out of the seal bore of packer  220   a . Pressuring annulus  24  above isolated interval  41  before pulling stinger  210  out of valve sub  222  prevents fluids in interval  41  from flowing upwardly and into annulus  24  as stinger  210  is repositioned. Referring momentarily to FIG. 8, raising stinger  210  causes caming surface  324  on latch members  320  of collet  330  to engage the lower surface of packer  220   a  and forces latch members  320  into a retracted position permitting stinger  210  to be pulled out of the flow bore of packer  220   a . Valve sub  222   a  is then actuated so that flapper member  223   a  closes off the seal bore through packer  220   a  and prevents pressurized fluid above from flowing through packer  220   a  and from entering isolated annular interval annulus  41  as shown in FIG. 10B. In this manner, a new isolated annular interval can be created above the actuated flapper sub  220   a  and can be pressurized in order to frac adjacent zone  35 , as described below.  
     [0117] Referring to FIGS. 4 and 10B, if excess proppant remains in workstring  100  or bottom hole assembly  200  after treating interval  36 , it can be “reversed out” by pumping fluid down annulus  24  from the surface where it passes around unset packers  220  and enters bottom hole assembly  200  via ports  212 . Such fluids then flow back up through bottom hole assembly  200  and tubing string  100  to clear excess proppant, allowing the next treatment to then take place.  
     [0118] Referring now to FIGS.  10 B- 10 D, to treat the next producing zone  35 , BHA  200  is raised and detector assembly  207  detects, identifies and locates the perforations  38  in the interval or region adjacent zone  35 . When BHA  200  is raised, the latch members  320  on stinger  210  engages the lower most surface on packer  220   b . With the surfaces thus engaged, raising stinger  210  thereby also raises the remaining stack of packers  220   b - 220   f . Because packers  220   b - 220   f  are not set, there is not enough reactive force applied by the packers to latch members  320  of collet  330  as is required to cause latch members  320  to retract. Once again, knowing the fixed distances associated with detector assembly  207  and stinger  210 , stinger  210  is raised to a position where packer  220   b  is in blank pipe above the region of perforations  38  as shown in FIG. 10B. With packer  220   b  above perforations  38 , surface controller  54  (via supervisory sub  203 ) signals solenoid valve  244   b  which, in turn, actuates hydraulic actuator  240   b  to expand packer  220   b  so that it seals with the wall of casing  22  at the location shown in FIG. 10C. Stinger  210  may thereafter be raised slightly to sever the shear pin (not shown) securing packer  220   b  to the packer stack above it and then can be lowered, if needed, so as to locate ports  212  just above perforations  38 , such position being represented by the dashed lines in FIG. 10C. Fracing fluid is then pumped downhole through tubing  100  and out ports  212  of stinger  210  so as to treat producing zone  35 . As before, pressure is monitored and pumping is reduced and then shut down at the surface before a spike in downhole pressure causes a dangerous overpressure at the surface. Likewise, data transmitted by the other downhole sensors, such as temperature sensor  250  and tilt sensors  290 , is likewise monitored at the surface and evaluated. When zone  35  has been treated, annulus  24  is pressured and stinger  210  is raised to a position above expanded packer  220   b , at which time flapper member  223   b  of valve sub  222   b  closes thereby sealing interval  43  from upper annulus  24  and isolating zone  35  as shown in FIG. 10D. In a similar manner, using detector assembly  207 , perforations  37  into zone  34  are located, packed off and the zone treated. Packers  220   d, e  and f may then be used to treat upper zones (not shown) as BHA  200  is raised still further.  
     [0119] In the manner thus described above, packers  220   a - f  are actuated remotely from the surface, and are actuated sequentially and selectively to isolate specific wellbore intervals so as to enable well treatment operations that are specifically tailored for the particular zone that is adjacent to the isolated interval. The embodiment of the invention thus described permits each zone, in a well containing several producing zones, to be treated one at a time, and ensures that each zone can be treated in a manner that enhances the potential for maximizing the recovery of valuable hydrocarbons from that particular zone, and from the well as a whole. In contrast to conventional packers and work strings previously used in well treatment operations, the embodiments of the invention described above allow packers to be set and well intervals to be isolated without requiring mechanical movement of the work string or the pressuring of fluids contained in the work string. Instead, once they are properly positioned, the packers are set simply and quickly via electrical signals that are communicated downhole via conductors. Further, the severe forces that are imposed on a work string that employs weight set packers are eliminated.  
     [0120] Referring now to FIG. 11A, another preferred embodiment of the well treatment apparatus and method is shown in which composite coiled tubing  100  is connected to a bottom hole assembly  400  having a series  201  of connected BHA components and a downwardly extending stinger  210 . BHA component series  201  include a connector sub  202 , supervisory sub  203 , hydraulic distribution sub  204 , gamma tool  205 , a detector assembly  207 , power distribution sub  208  and sensor sub  209 , all as previously described. Disposed in spaced apart position along stinger  210  are packers  420   a - c . A flapper valve assembly  422  is connected to each packer  420 . Stinger  210  includes a solenoid valve and hydraulic actuator such as those previously described with reference to FIGS.  6 - 7  that are controlled by supervisory sub  203  so as to cause each packer  420  to expand and seal against the well casing upon receipt of the appropriate signal. Each packer  420   a - c  is connected to stinger  210  by a latch member (not shown) that is released upon actuation of packer  420 .  
     [0121] Referring to FIGS. 11A and 11B, bottom hole assembly  400  may be employed to treat, for example, zones  450 ,  451  which have been perforated at intervals  452 ,  454  respectively. To treat these zones, bottom hole assembly  400  is first lowered to a position below zone  450 . The bottom hole assembly  400  is then be raised and, using detector assembly  207  in conjunction with gamma tool  205 , packer  420   a  is positioned above the perforated interval  452  in blank pipe away from any casing joints. At this juncture, packer  420   a  is actuated so as to isolate the interval  441  of the cased borehole below packer  420   a , the packer  420   a  in its expanded or set position being represented by dashed lines in FIG. 11A. The fracing procedure is then commenced with temperature and pressures continuously monitored downhole as previously described. When the fracing operation is complete, and prior to screen out, bottom hole assembly  400  is raised such that stinger  210  is pulled out of set packer  420   a , at which time flapper valve assembly  422   a  closes, as shown in FIG. 11B. The above-described procedure is then repeated such that packer  420   b  is positioned above perforated interval  454  in zone  451 , and then actuated. Thereafter, stinger  210  can be reciprocated within packer  420   b  to center ports  212  in relation to perforated interval  454 . A producing zone above zone  451  may thereafter be treated in a similar manner by employing packer  420 C. The embodiment shown in FIGS.  11 A-B having spaced apart packers along stinger  210  are believed to have particular utility in treating formations having very long intervals with many producing zones.  
     [0122] The embodiments of the invention described to this point preferably include the use of composite coiled tubing  100 . Because such composite tubing cannot be subjected to substantial tension or compression, conventional weight set packers cannot be employed, such that the electrically controlled, and electrically/hydraulically actuated packers previously described are the preferred packers for use with composite coiled tubing  100 . Additionally, however, other packers and packer actuators may be employed. For example, a propellant may be provided in the stinger body adjacent to each packer as the actuator. The propellant can then be electrically ignited in response to a signal from the surface controller  54 . The pressure created by the burning propellant may be used to actuate mechanical slips as necessary to set the packer. As known to those skilled in the art, many existing wire line packers are set using a propellant. Thus, referring now to FIGS. 9 and 12, it will be understood that a signal from surface controller  54  relayed via to supervisory module  203  along wires  144  may then cause power distribution module  381  in power sub  208  to ignite the propellant  226  via power sent along conductors  225  (FIG. 12) and thereby expand the associated packer  227 . In this manner, the hydraulic distribution system previously described would not be necessary.  
     [0123] Another embodiment of the invention includes the use of electric motors as actuators for the packers  220   a - f . In such an arrangement, associated with each packer  220   a - f  is a separately controlled electric motor (not shown) housed in the body of stinger  210 . Referring again to the control schematic of FIG. 9, each motor constitutes a control device  358  and receives power from power distribution module  381  in power sub  208  and is controlled by controller  354  in supervisory module  203 . Upon receipt of the appropriate control signal from surface controller  54 , processor  354  in supervisory module  203  causes power to be switched to the motor. Thereafter, the motor drives any of a number of conventional mechanical energy converters, such as a screw or screw and piston combination, and actuates mechanical slips that cause the associated packer to expand. See for example, U.S. patent application Ser. No. 09/678,817 filed Oct. 4, 2000 entitled Actuator Assembly, hereby incorporated herein by reference.  
     [0124] Another preferred embodiment of the present invention is best described with reference to FIG. 13 wherein bottom hole assembly  600  is shown connected to coiled tubing  100  and disposed in a borehole  601  adjacent to zone  640 . BHA  600  generally comprises a connected series of BHA components  201  and stinger  610  extending therefrom. BHA component series  201  include a connector sub  202 , supervisory sub  203 , hydraulic distribution sub  204 , gamma tool  205 , detector assembly sub  207 , sensor sub  209 , and tilt sensors  290   a - c  all as previously described. Stinger  610  includes an internal flowbore, like bore  211  shown in FIG. 4, in fluid communication with flowbore  146  (FIG. 3) of coiled tubing  100 . Stinger  610  includes ported discharge sub  614  having ports  612  for directing fracing fluid into zone  640  that is to be treated.  
     [0125] Disposed in spaced apart relation on stinger  610  are upper cup packer  616  and lower packer  618 . Packers  616 ,  618  are hydraulically actuated via interconnection with hydraulic distribution module  204  so that they can repeatedly be expanded (set) to engage the casing side wall and contracted (unset or released) so that bottom hole assembly  600  can be repositioned in the wellbore. Unlike the packers in the embodiments previously described, packers  616 ,  618  remain fixed to stinger  610  in bottom hole assembly  600 . Packer  618  may be, for example, a Halliburton type RR4 packer. Alternatively, packer  618  may likewise be a cup packer such as packer  616  with the cup facing upwards and thus facing in the opposite direction as cup packer  616 .  
     [0126] Bottom hole assembly  600  further includes an anchor  630  at the terminal end of stinger  610 . Anchor  630  may be, for example, a single grip, multiset compression packer. An additional packer, such as packer  618 , may likewise be employed as anchor  630 . An anchor such as anchor  630  may likewise be employed at the upper end, lower end, or both ends of the bottom hole assemblies  200 ,  400 , previously described, where desirable for added stability. BHA  600  further includes tilt sensors  290   d ,  290   e  below anchor  630 . Like tilt sensors  290   a - c  that are positioned above cup packer  616 , sensors  290   d,e  are used to sense a change in inclination (tilt) of the casing, indicating a characteristic of the fracture geometry and propagation.  
     [0127] Referring still to FIG. 13, packers  616 ,  618  together form a straddle packer arrangement with upper cup packer  616  being spaced apart from lower packer  618  a fixed distance selected for isolated zone  640  which has been perforated in interval  642 . In operation, bottom hole assembly  600  is lowered on coiled tubing  100  to a position where detector assembly  207  is below zone  640 . Sub assembly  600  is then raised and perforated interval  642  located by detector assembly  207 . Gamma tool  205  may likewise be employed to verify the location of zone  640  and perforated interval  642 . Thereafter, bottom hole assembly  600  is raised the fixed and known distance between ported sub  614  and detector assembly  207  so as to align ports  612  with the perforated interval  642 . In this position, anchor  630  is actuated hydraulically so as to set and stabilize bottom hole assembly  600 . Likewise, hydraulic packer  616 ,  618  are actuated so as to isolate the interval  602  adjacent to zone  640 . The dashed lines in FIG. 13 represents packers  616 ,  618  and anchor  630  in their expanded positions. Proppant fracing fluid is then pumped from the surface through coiled tubing  100  and stinger  610  where it exists through ports  612  and enters formation  640  through perforated interval  642 . Pressure sensors  354 ,  358 ,  362  in sensor sub  209  monitor the downhole pressure as previously described so that a dangerous screen out condition can be predicted. When the stimulation procedure has been completed, packers  616 ,  618  and anchor  630  are retracted, and bottom hole assembly  600  may then be raised to another position to treat another producing zone. As understood by those skilled in the art, once set, cup packer  616  seals pressure from below packer  616  in interval  602  but will allow fluid to flow downwardly through the annulus  24  and past cup packer  616 . Such a packer is advantageous in that it provides a means to flush sand and remaining fracing fluid from bottom hole assembly  600  before beginning fracing operations in the next zone. This is accomplished by raising bottom hole assembly  600  above the treated zone  640  to a blank area of casing beneath the next zone that is to be treated. Packers  616  and  618  are then actuated so as to engage the casing wall. Fluid may then be pumped down the annulus from above the isolated interval that exists between the packers where it is allowed to pass downwardly past cup packer  616  and into the ported sub  614  through ports  612 . Once this “reverse circulation” has flushed out the sand and any undesirable fluid, bottom hole assembly  600  is then raised to the next zone where packer  616 ,  618  and anchor  630  are then set.  
     [0128] Referring to FIG. 14, bottom hole assembly  700  is shown connected to coiled tubing  100  and disposed in borehole  701  adjacent to zone  740 . Bottom hole assembly  700  is substantially the same as assembly  600  previously described with respect to FIG. 13; however, bottom hole assembly  700  includes two cup packers  716 . Packers  716  may be identical to packer  616  previously described. Two such packers  716 , or more, are provided on bottom hole assembly  700  to enhance tool reliability and eliminate the necessity of withdrawing bottom hole assembly  700  should the first packer  716  fail. In this embodiment, lower packer  718  is also a cup packer and is identical to packers  716 , however, cup packer  718  is positioned with its cup facing uphole. As will be understood, bottom hole assembly  700  may likewise include two or more lower packers  718  for enhanced tool reliability. Operation of BHA  700  is identical to that described with respect to BHA  600 , with packers  716  being selectively actuatable.  
     [0129] The specific examples of the invention described to this juncture have related to the use of composite coiled tubing, which is preferred for deep well applications; however, it is to be understood that metal coiled tubing can also be employed in certain applications, although certain advantages and features of the preferred composite tubing are lost. For example, conductors cannot be embedded within the metal tubing, but must be supported within or on the outside of the tubing string. Although this can be accomplished, it is less convenient and exposes the conductors to abuse due to the harsh conditions prevalent when the tubing is injected into a borehole. Further, metal coiled tubing fatigues relatively quickly when cycled in and out of wells. By contrast, composite coiled tubing is believed to have a significantly longer pipe life compared to that of metal coiled tubing in the well stimulation activities described herein.  
     [0130] While preferred embodiments of this invention have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit or teaching of this invention. The embodiments-described herein are exemplary only and are not limiting. Many variations and modifications of the system and apparatus are possible and are within the scope of the invention. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims which follow, the scope of which shall include all equivalents of the subject matter of the claims.