US20040238167A1

US20040238167A1 - Method of installing control lines in a wellbore

Info

Publication number: US20040238167A1
Application number: US10/445,494
Authority: US
Inventors: C. Pinto; David Johnson; Stephen Thompson
Original assignee: Individual
Current assignee: Individual
Priority date: 2003-05-27
Filing date: 2003-05-27
Publication date: 2004-12-02

Abstract

A method and apparatus for perforating a casing in a wellbore wherein the casing has control means attached thereto, which method and apparatus includes inserting a detectable source with the control means extending a selected length of the control means; inserting a sensing means in the casing for sensing the detectable source; sensing the location of the detectable source at selected levels in the casing; recording the direction of the detectable source at the selected levels in the casing; inserting perforating means in the casing, the perforating means for perforating the casing, the perforating means having orienting means for selectively positioning the perforating means relative to the recorded direction of the detectable source at the selected levels in the casing; and perforating the casing at a selected orientation relative to the sensed detectable source at the selected levels in the casing.

Description

BACKGROUND OF THE INVENTION

1. Field of Invention

This invention relates to well drilling and completion devices and processes. More specifically, the invention is concerned with providing devices and methods that improve the ability to azimuthally orient perforating devices away from downhole cables within a perforating zone. And more particularly, to such an apparatus and process wherein a detectable source is employed to identify the location of the control lines.

2. Background of the Invention

Conventional wells and well completions typically provide little or no downhole instrumentation and/or fluid control capability. Some conventional well completion procedures are relatively simple, essentially running production or injection tubing into the well along with perforating, gravel packing, and/or logging steps as needed. Pressure and flow control in conventional oil, gas or other fluid-producing wells typically use valves and instruments located at or near the surface in a Christmas tree arrangement. Formation fluids are typically produced until a downhole problem occurs, e.g., reservoir pressure declines or the water-cut increases or something else happens downhole that significantly reduces production or prevents the well from further commercial operation.

To evaluate the cause of production or injection problems in a conventional well, the well is typically taken off-line and one or more logging tools supported by a wireline are run through the tubing within the well. The logging tools may be used to check downhole fluid pressures, fluid types, zonal flowrates or other parameters at one or more depths to try to determine the cause of the production or injection decline and the corrective action needed. Once the problem is determined and/or new production or injection zones identified, the wireline tools are typically removed and a second re-entry into the off-line well is accomplished to correct the problem, e.g., using a workover rig. For example, a second re-entry might lower a perforating tool to reperforate/re-complete the well at a new producing level. These conventional well completions, re-entries, and recompletions may consume unacceptable lost production time and costs, especially when applied to deepwater, multi-producing zone, high temperature, and/or high-pressure reservoirs and wells. In contrast to conventional wells and well systems, the term “intelligent” and “smart” wells and well systems may refer to wells having downhole process control, instrumentation, and/or related components. Other terms used for intelligent or smart well systems include SCRAMS (Surface Controlled Analysis and Management System), IRIS (Intelligent Remote Implementation System), and RMC (Reservoir Monitoring & Control). But no matter what these well systems are called, they enable real-time downhole operation, surveillance, data interpretation, intervention, and/or process control in a continuous feedback loop. The smart wells allow problems to be detected and possibly minimized or corrected without taking the well off-line. Smart well systems can therefore operate for long periods without the need to shut down and introduce instrumentation or additional wireline tools. However, the introduction of perforating tools is still typically required during the less frequent workover processes.

A smart well system typically uses downhole tubing, cables or other means for transmitting power, real-time data or control signals to or from surface equipment and downhole devices such as transducers and control valves. Power and signals typically use transmission means such as electric and/or fiber optic cables, but other transmission devices can include fluid tubing. Other well applications may also have cables or other transmission means present during operations that may include perforating. Other well processes and applications that may require downhole transmission means include wells having a submersible electric pump, measurement while drilling (MWD) methods, and the use of downhole directional & inclination indicators, hydraulic actuators, and power supplies, e.g., for data transmission using mud pulse telemetry. Perforating or re-perforating a well having a downhole cable or other transmission device must avoid damaging the transmission device during the perforating process, typically requiring a step of azimuthally orienting a directional-perforating device. The orienting step directs the perforating action away from nearby cables or other devices in the well. Orientating methods may include magnetic oriented techniques (MOT), obtaining positional data from downhole probes, using gravity-actuated orienting devices for non-vertical boreholes, limiting operations to within guided downhole paths, obtaining orienting data from gyroscopes, and using mechanical indicators or orientation subs.

However, the orienting step can add significant cost and/or present feasibility problems, especially when high temperature, corrosive fluids, high pressures, multiple completion zones, or other difficult downhole conditions are encountered. The added costs and problems can also be compounded by the added time to accomplish the orienting step for deep offshore wells. For example, application of current MOT techniques may be limited by high downhole temperatures and since typical well depths have been increasing, increasing downhole temperature problems for MOT processes may be encountered.

3. Description of Related Art

After a wellbore has penetrated a formation and a casing has been cemented in place, the formation must be communicated with the wellhead so that valuable hydrocarbons or other effluents can be extracted from the wellhead. The standard method of communicating the formation with the wellhead is to perforate the casing so that the hydrocarbons or other effluents may penetrate the casing. The methods of perforating the casing are well known to those of ordinary skill in the art of oil, gas and geothermal exploration and extraction. U.S. Pat. Nos. 3,706,344 and 3,871,448 to Roy R. Vann teach a permanent completion technique which can advantageously be employed in completing a wellbore. Reference is made to these prior patents, to U.S. Pat. Nos. 3,931,855; 3,812,911; and 4,040,485; and to the art cited therein for further background of the present invention.

The well completion method and apparatus of the present invention is applicable to any well that is completed with casing cemented across the producing interval, which implies perforating is required, and particularly applicable to deep, high-temperature, high-pressure wells. For example, such a well might be over 10,000 feet deep, have a bottomhole temperature of about 300° F., and bottomhole pressure of over 5,000 psi. Because of this environment, it is essential for safety reasons that control be maintained over the well at all times. Such control is maintained by using a hydrostatic head of well fluids such as mud to insure that the bottomhole pressure exceeds the formation pressure and later setting a packer in the eased wellbore. Typically the production casing consists of a number of individual lengths of casing coupled together by means of collars that are in a spaced relationship along the length of the production casing. It is known in the trade to include identification pip tags at the collars so that they may be identified by detection means, the primary use of such pip tags is for depth location only. The pip tags enable the operator to tie into an exact well depth for any vertical correlation work being done.

It would be desirable to be able to run the control lines into the wellbore across the interval to be perforated, attached to the outside of the production casing. The sensing of wellbore temperature is measured from that exact location at a selected depth, which will not be exactly what the temperature is on the inside of the casing, but will be similar given enough thee for equalization. To sense pressure, the pressure sensor is communicated to the internal casing pressure by means of a port between the interior of the casing and the sensor itself. After the production casing is inserted in the wellbore, the location of the collars are known, however the collars cannot prevent the skewing of the control lines circumferentially around the outside of the production casing due to the high pressures and other conditions encountered while inserting the casing. Thus, the precise location of the control lines on the perimeter of the casing at any given depth is not known, so that the opportunity, or probability, for damaging the control lines during process of perforating the production casing is high, which would render them either partially or wholly useless. Therefore there is a need for a method and an apparatus for locating the precise location of the control lines at a selected depth so that the perforation means may be oriented in a selected direction to avoid damaging the control lines. Method and apparatus for accomplishing this purpose is the subject of the present invention.

SUMMARY OF THE INVENTION

In one embodiment, the invention adds a position signaling or a detectable signature element to a cable or other equipment to be protected and a signal or signature position detector that, at least in part, controls the orientation of a directed perforating device. The detection of the position signal or signature allows the perforating device to be oriented in a desired azimuthal position that avoids damaging the cable. Signal emitting sources can include a radioactive material added to an encapsulating composition of a downhole cable or an irradiated cobalt alloy wire along with electric wires in the cable. Various types of signal detectors can be used, e.g., a Geiger, Mueller, or scintillation counter, combined with a moveable apertured shield or another directional device, e.g., a Rotascan and/or Tracerscan model manufactured by Halliburton and available-in Houston, Tex. or a POT-C manufactured by Schlumberger and available in Houston, Tex. The position signal detector assembly is preferably connected to a scallop, strip gun, or other conventional directed perforating tool (e.g., a Model OP perforating tool supplied by Halliburton) in such a way that perforations are directed away from the detected cable or cable assembly. Connecting the directed perforating tool and the signal detector allows a reliable perforation and reperforation of the well without. re-entry and without damage to the cable or other downhole equipment not intended to be perforated.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a fragmentary, partly diagrammatic, partly cross-sectional elevation of a wellbore containing apparatus of the present invention. [0013]
FIG. 2 is a schematic representation of the apparatus of the present invention. [0014]
FIG. 3 is a cross-sectional view of the apparatus of FIG. 2 through a first element of orientation means of the apparatus of the present invention. [0015]
FIG. 4 is a cross-sectional view of the apparatus of FIG. 2 through the detection means of the apparatus of the present invention. [0016]
FIG. 5 is a plan view of the apparatus of FIG. 2 inside the wellbore casing. [0017]
FIG. 6 is a schematic view of one embodiment of the detectable source of the invention attached to the control means. [0018]
FIG. 7 is a schematic view of a second embodiment of the detectable source of the invention attached to the control means.[0019]

DETAILED DESCRIPTION OF THE INVENTION

FIG. 1 discloses a partial sectional view of a cement-[0020] sleeved wellbore 20, at a particular depth in a formation 10. Wellbore 20 is a cylindrical, cement casing extending from the surface to a selected depth in formation 10 where valuable effluent may reside. Wellbore 20 may be capped at the surface (not shown) to maintain pressure in the wellbore. Shown within wellbore 20 is production casing 30 that is cemented in formation 10 by wellbore 20, and containing apparatus of the present invention consisting of a tool 40 which has a plurality of components for communicating the wellbore with the formation 10. Tool 40 consists of a rotational means 50, a detection housing 60, a means of perforation 70, and means 45 for lowering tool 40 to a desired depth in production casing 30. FIG. 1 discloses that wellbore 20 has been communicated with formation 10 by means of a plurality perforation holes 140 through production casing 30, wellbore 20 and into formation 10 to enable effluents in formation 10 to flow into production casing 30.
[0021] Production casing 30 is typically about 4.5 to 9 inches inside diameter d and constructed of steel. Production casing 30 is generally inserted inside a larger steel tube that is run from the surface to a shallower depth. Consecutively smaller diameters of casing are run to deeper depths, each in side the previous. Casing sizes can be of about 20 inches inside diameter at the surface, and narrowing to about 9 inches inside diameter at the bottom of the wellbore. Production casing 30 may be 5,000 to 10,000 feet in length, and is of sufficient strength to withstand 5,000 pounds per square inch pressure at such depths. Attached to the outside of production casing 30 is control means 80 extending a selected distance in the wellbore. Control means 80 may consist of an electrical line, a single tube containing an electrical lead for operating a device, a capillary tube for determining the pressure of the wellbore at a selected depth, and/or a plurality of electrical lines or leads, capillary tubing, fiber optic cables, or other control means for measuring various parameters in the wellbore, or for operating a variety of devices in the wellbore. Control means 80 is attached to production casing 30 by a plurality of casing collar protector clamps that are placed over each casing collar 35 (FIGS. 6 & 7) which may be located at selected and known intervals along production casing 30. The collars are located at the end of each joint of casing, and are merely the apparatus to couple the joints of casing together. However, they typically are a larger outside diameter than casing itself. In FIG. 1, control means 80 includes a detectable source 90, which may be detected by detection means 68 at any selected depth along casing 30. Means 45 for lowering tool 40 in wellbore 20 is typically a bull nose, or sinker bars, or a combination thereof, that pull tool 40 into production casing 30 by gravity. The number of bull noses and/or sinker bars are selected based on the depth of production casing 30 and the wellbore pressure. These factors are well known to one of ordinary skill in the art and are not limitations to the present invention. Lowering means 45 is typically added to tool 40 by a threaded means projecting from the last device in the tool string in the well, and in this embodiment, from perforation means 70. Emanating horizontally from wellbore 20 are a plurality of perforations 140 which penetrate casing 30, wellbore 20 into formation 10.
FIG. 2 is an elevation view of [0022] tool 40 apart from the wellbore. Tool 40 is typically suspended in the wellbore by cable 95, and consists of three components, the rotational means 50, the detection housing 60, the perforation means 70, and means 45 for lowering tool 40 in the production casing 30. Rotational means 50 may be controlled by an operator at the surface at some point adjacent the wellbore by operation means 100 which communicates with tool 40 by means of communication cable 95 that may include an electrical source to operate tool 40. Alternatively, operation means 100 may be a programmed means, such as a computer. In an alternate embodiment, operation means 100 may include a transmitter or transceiver that may communicate with a receiver or transceiver in rotational means 50 to control operation of tool 40 and wherein tool 40 includes a source of electricity, such as a battery.
As shown in FIG. 2, intermediate in [0023] detection housing 60 is detection slot 65, which exposes detection means 68 (FIG. 4) to the interior of production casing 30. In this preferred embodiment, detection housing 60 is fabricated of a high density shielding/insulating material, such as lead or tungsten, thereby shielding detection means 68 from detecting the detectable source 90 from any direction other than through detection slot 65. The material selected for housing 60 is based on the type of detectable source 90, for example, if the detectable source 90 is a magnetic field device then, housing 60 would be not require a detection slot 65.
Referring to FIGS. 3, 4 and [0024] 5, FIG. 3 is a cross-sectional view of rotational means 50. In this preferred embodiment rotational means 50 is an electrical driven motor 55 in a cylindrical housing, that causes shaft 52 to rotate about its longitudinal axis, and in parallel with the longitudinal axis of production casing 30. In fixed relationship with rotational means 50 is cylindrical detection housing 60, which is threadedly attached to Shaft 52 of rotational means 50 such that detection housing 60 is fixed relative to rotational means 50, and thus synchronously rotates about the longitudinal axis of Shaft 52. Extending perpendicularly from the bottom of detection housing 60, co-axially with shaft 52, is detection housing shaft 62, which is sized and threadedly configured identical to shaft 52 for fixedly receiving perforation means 70. Thus, one can appreciate that detection housing 60 could be removed from device 40 and perforation means 70 attached directly to shaft 52. Perforation means 70 will rotate synchronously about the longitudinal axis of shaft 52 in fixed relationship to both shaft 52 and detection housing 60. Thus when detection means 68 is rotated about the longitudinal axis of shaft 52 within production casing 30 by rotational means 50, and when detection slot 65 becomes proximate to detectable source 90, the location of detectable source 90 may be noted relative to the then current position of shaft 52. Therefore, the exact location of control means 80 is then known at that selected depth in the wellbore. To ensure that the control means 80 is at the precise detected location relative to shaft 52, it may be desirable to rotate detection means 65 past detectable source 90 several times. Geometrically, detection housing 60 and perforation means 70 can be viewed as canisters, wherein the top surface of the canister includes a threaded receptacle (not shown) for receiving shafts 52 and 62, respectively and the bottom of the receptacle includes threaded means 62 and 72 for connecting to perforation means 70 and lowering means 45, respectively. In the preferred embodiment, detection housing 60 abuts firmly against the bottom of rotational means 50, and perforating means 70 abuts firmly against the bottom of detection housing 60. It may be desired to position gaskets at each abutment so that effluent from the wellbore is sealed from obstructing or interfering with the rotational aspects of device 40. Concomitantly, it may be desirable to fill detection slot 65 with a high-pressure, high-temperature glass (either limited or non-gamma ray absorbent material), or equivalent material, that would seal detection means 68 from the effluent without deteriorating the performance of the sensor. It should also be appreciated that there are other means by which detection housing 60 and perforating means 70 may be attached to rotation means 50, as would be known by one of ordinary skill in the art. For example, detection housing 60 and perforating means 70 could be mounted on a common shaft, or mounted is a single housing.
FIG. 5 depicts a plan, cross-section of perforating means [0025] 70. Perforating means 70 is shown to be resting adjacent production casing 30, which one of ordinary skill in the art would know is typical, since production casing 30 cannot be run perfectly vertical into formation 10. As noted above, perforating means 70 is threadedly attached to detection housing 60 such that perforating means 70 is also fixed relative to rotational means 50, thus also fixed in relationship with the axis of shaft 52 so that the radial alignment of perforating means 70 relative to shaft 52 is also known, and therefore the location of control means 80 is known when detected by detection means 68. The location and position of perforating means 70 may be pre-oriented such that when detection means 68 identifies the location of detectable source 90 adjacent or within control means 80 at that selected depth (so as to avoid the casing collars) and within the area of valuable effluent, then perforation of production casing 70 and wellbore 20 is simply accomplished by firing perforation means 70 in a selected direction away from control means 80. Alternatively, by orienting perforating means 70 in the same orientation relative to the position of detection means 68, perforation of production casing 30 and wellbore 20 is accomplished by rotating shaft 52 a selected number of degrees away from control means 80, and firing perforation means 70.
Since it is possible to selectively fire perforation means [0026] 70 a plurality of times, it is then possible, after the initial perforating the casing, to relocate tool 40 to a different selected depth, and to again rotate detection means 68 past detectable source 90, (which, as noted above, may have moved circumferentially with control means 80 about production casing 30 an unknown distance) to again locate detectable source 90 at that newly selected depth, and then again perforate production casing 30 and wellbore 20 ind into formation 10. Referring again to FIG. 2, perforation means 70 is shown to include a plurality of perforation guns 75 projecting outwardly from the longitudinal axis of shaft 52. This process of perforation may be continued until the complete production casing 30 and wellbore 20 have been perforated through the selected area of the valuable effluent. Since detectable source 90 is permanently installed as part of control means 80, if perforation means 70 fails for any reason, tool 40 may be removed from production casing 30, repaired, and reinserted in production casing 30 for completion of the work. Alternatively, if it is subsequently desired to perforate production casing 30 and wellbore 20 at a different selected depth, tool 40 may again be inserted in production casing 30, and the location of control means 80 may still be located, even though it may have circumferentially shifted about production casing 30 from forces within wellbore.
In another embodiment of the method of the invention, [0027] tool 40 may be assembled without perforation means 70, and tool 40 may be lowered in production casing 30 for the selected length of the casing where perforations are desired. By continuously monitoring the location of detectable source 90 at selected intervals, the exact location of control means 80 throughout the selected length of production casing 30 may be communicated to operation means 100, thereby enabling a three-dimensional mapping, or profiling, of control means 80 relative to production casing 30. In this embodiment, the azimuth (a horizontal direction expressed as the angular distance between the direction of a fixed point, such as the position of shaft 52, or the direction toward magnet north pole) denoting the direction of detectable source 90 at each selected depth, would be communicated to operation means 100, to enable the three-dimensional mapping of production casing 30. Once the selected length of production casing 30 has been profiled, tool 40 may be removed from production casing 30, the detection means replaced with perforation means 70, and tool 40 run back into production casing 30 for the perforation step. By having previously profiled control means 80 relative to production casing 30, perforation means 70 may be optimized. Directional perforating can be performed by utilizing a directionally weighted perforated tool and pre-setting the azimuthal direction for a specific depth. For example, it may be possible to string a larger number of perforating guns in perforation means 70 to enable a more efficient and time savings perforation of the formation, as would be obvious to one of ordinary skill in the art.
FIGS. 6 and 7 are schematic diagrams of portions of [0028] production casing 30 showing detectable source 90 attached thereto, but without showing control means 80. In FIG. 6, detectable source 90 can be a magnetic or irradiated wire extending the selected length of production casing 30, and held in place by a plurality of collars protector clamps 35. Alternatively, detectable source 90 could be a capillary tube containing the magnetic or irradiated wire, or a detectable radioactive fluid. FIG. 7 shows detectable source is a magnetic or irradiated strip, adjacent control means 80, and extending a selected distance above and below each collar 35. In either case, the detectable source 90 and control means 80 are shown to be vertically aligned along the length of production casing 30, however, as noted above, and as known to one of ordinary skill in the art, upon insertion of casing 30 into formation 10, the process of insertion, and the conditions of the formation, will cause control means 80 and detectable source 90 to be skewed circumferentially about production casing 30.
[0029] Detectable source 90 may be of various compositions. For example, control means 80 may include a capillary tube extending the length of control means 80, closed at both ends, and containing a detectable gas, such as Krypton, or an irradiated source, such as an irradiated wire. Equivalently, an irradiated wire may be included as part of the control means. Detection means 68 could then be a Geiger Mueller tube, or an equivalent radiation/gamma-ray detector or scintillation counter, combined with a moveable apertured shield or another directional device, e.g., a Rotascan and/or Tracerscan model manufactured by Halliburton and available-in Houston, Tex. or a POT-C manufactured by Schlumberger and available in Houston, Tex. Alternatively, detection means 68 could be a directional variation magnetic field sensor. The present invention is not limited by the detectable source or the detection means. It is only necessary that the detectable source extend a substantial length of control means 80 in the selected area of the wellbore to be perforated. The detectable source may be discontinuous, as long as it enables the operator of the tool to identify the location of the control tubing at a selected depth and, at the same time, avoid the casing collars. Detectable source 90 could be a wire having a major component being cobalt. Irradiated wire may be produced by spooling the wire in-line through the neutron field emitted by a nuclear reactor. In addition, the Detectable source 90 may be installed inside control means 80 during the manufacturing process of control means 80, or attached to control means 80 during the production casing installation process.
Perforation means [0030] 70 is commonly a perforating gun, or a string of guns. The term “gun” implies a length of perforating charges that can cover a selected number of feet to be perforated. Guns usually have charges ranging from 2 to 12 shots per foot with these charges spaced circumferential at various and known angles from charge to charge. A string of guns implies connecting multiple gull segments of charges. The charges can be spaced to leave a long length of non-perforated interval between segments where perforations are required.
Accordingly, the scope of the invention should not be determined by the specific embodiments illustrated herein, but rather in light of the full scope of the claims appended hereto. [0031]

Claims

We claim:

1. A method for perforating a casing in a wellbore, the casing having control means attached thereto, the method comprising:

(a) inserting a detectable source with the control means, the detectable source extending a selected length of the control means;

(b) inserting a sensing means in the casing, the sensing means for sensing the detectable source;

(c) inserting perforating means in the casing, the perforating means for perforating the casing, the perforating means having orienting means for selectively positioning the perforating means relative to the direction of the detectable source;

(d) sensing the location of the detectable source; and

(e) perforating the casing at a selected orientation relative to the sensed detectable source.

2. The method of claim 1 wherein the detectable source is a source of radiation.

3. The method of claim 2 wherein the source of radiation is an irradiated wire.

4. The method of claim 1 wherein the step of inserting the detectable source includes inserting at least one capillary tube extending a selected length of the control means.

5. The method of claim 4 wherein the step of inserting at least one capillary tube includes the step of inserting the detectable source in the capillary tube.

6. The method of claims 5 wherein the detectable source is a fluid.

7. The method of claim 2 wherein the sensing means for sensing the source of radiation is a gamma ray detector.

8. The method of claim 1 wherein the detectable source is a magnetic wire.

9. The method of claim 8 wherein the sensing means is a directional variation magnetic field sensor.

10. The method of claim 1 wherein the step of perforating the casing at a selected orientation relative to the detectable source includes orienting the perforating means away from the control means.

11. The method of claim 1 wherein the orienting means is a motor for providing rotational bias to the sensing means and the perforating means.

12. The method of claim 1 wherein the perforating means is a perforating gun.

13. A method for perforating a casing in a wellbore, the casing having control means attached thereto, the method comprising:

(a) inserting, in fixed relationship with the control means, at least one capillary tube, the capillary tube extending a selected length of the control means;

(b) inserting in the capillary tube a detectable source, the detectable source extending a selected length of the capillary tube;

(c) inserting a sensing means, the sensing means for sensing the detectable source;

(d) inserting a perforating gun in the casing, the perforating gun for perforating the casing and the wellbore, the perforating gun having orienting means for selectively positioning the perforating gun relative to the direction of the detectable source;

(e) detecting the location of the detectable source; and

(t) perforating the casing at a selected orientation away from the control means.

14. The method of claim 13 wherein the source of radiation is an irradiated wire.

15. The method of claims 16 wherein the radiation source is a fluid.

16. The method of claim 14 wherein the sensing means for sensing the source of radiation is a gamma ray detector.

17. The method of claim 13 wherein the detectable source is a magnetic wire.

18. The method of claim 17 wherein the sensing means is a directional variation magnetic field sensor.

19. The method of claim 13 wherein the step of perforating the casing at a selected orientation relative to the detectable source includes orienting the perforating gun.

20. The method of claim 19 wherein the orienting means is a motor for providing rotational bias to the sensing means and the perforating gun.

21. A method for perforating a casing in a wellbore, the casing having control means attached thereto, the method comprising:

(c) sensing the location of the detectable source at selected levels in the casing;

(d) recording the direction of the detectable source at the selected levels in the casing;

(e) inserting perforating means in the casing, the perforating means for perforating the casing, the perforating means having orienting means for selectively positioning the perforating means relative to the recorded direction of the detectable source at the selected levels in the casing; and

(f) perforating the casing at a selected orientation relative to the sensed detectable source at the selected levels in the casing.

22. The method of claim 21 wherein the step of recording the direction of the detectable source at the selected levels in the casing includes the step of removing the detection means prior to inserting the perforating means in the casing.

23. The method of claim 21 wherein the detectable source is a source of radiation.

24. The method of claim 23 wherein the source of radiation is an irradiated wire.

25. The method of claim 21 wherein the step of inserting the detectable source includes inserting at least one capillary tube extending a selected length of the control means.

26. The method of claim 25 wherein the step of inserting at least one capillary tube includes the step of inserting the detectable source in the capillary tube.

27. The method of claims 26 wherein the detectable source is a fluid.

28. The method of claim 23 wherein the sensing means for sensing the source of radiation is a gamma ray detector.

29. The method of claim 21 wherein the detectable source is a magnetic wire.

30. The method of claim 29 wherein the sensing means is a directional variation magnetic field sensor.

31. The method of claim 21 wherein the step of perforating the casing at a selected orientation relative to the detectable source includes orienting the perforating means away from the control means.

32. The method of claim 21 wherein the orienting means is a motor for providing rotational bias to the sensing means and the perforating means.

33. Apparatus for perforating a casing in a wellbore, the casing having control means attached thereto, the apparatus comprising:

(a) a detectable source, the detectable source for inserting in a fixed relationship with the control means, the detectable source for identifying the location of the control means, the detectable source sized to extend a selected length in the casing;

(b) orientation means, the orientation means for selectively orienting sensing means and perforating means relative to the detectable source;

(c) sensing means for sensing the detectable source, the sensing means for insertion in the casing, the sensing means in fixed relationship to the orientation means; and

(d) perforating means for perforating the casing, the perforating means 11 fixed relationship with the orientation means.

34. The apparatus of claim 33 wherein the detectable source is a source of radiation.

35. The apparatus of claim 34 wherein the source of radiation is an irradiated wire.

36. The apparatus of claim 33 additionally including at least one capillary tube, the at least one capillary tube sized to extend a selected length of the control means, the capillary tube for receiving the detectable source.

37. The apparatus of claim 33 wherein the detectable source is a fluid.

38. The apparatus of claim 34 wherein the sensing means is a gamma ray detector.

39. The apparatus of claim 33 wherein the detectable source is a magnetic wire.

40. The apparatus of claim 39 wherein the sensing means is a directional variation magnetic field sensor.

41. The apparatus of claim 33 wherein the orienting means is a motor for providing rotational bias to the sensing means and the pert-orating means.

42. The apparatus of claim 33 wherein the perforating means is a perforating gun.

43. Apparatus for perforating a casing in a wellbore, the casing having control means attached thereto, the process comprising:

(a) at least one capillary tube in fixed relationship to the control means, the at least one capillary tube sized to extend a selected length of the control means, the capillary tube for receiving a detectable source

(b) the detectable source for identifying the location of the bundle, the detectable source sized to extend a selected length in the capillary tube;

(c) a motor for providing rotational bias to sensing means and perforating means, the motor for selectively orienting a perforating gun relative to the detectable source;

(d) sensing means for sensing the detectable source, the sensing means for insertion in the casing, the sensing means communicating with and in fixed relationship to the motor; and

(e) the perforating guns for perforating the casing, the perforating gun in fixed relationship to the motor.

44. The apparatus of claim 43 wherein the detectable source is a source of radiation.

45. The apparatus of claim 44 wherein the source of radiation is an irradiated wire.

46. The apparatus of claim 43 wherein the detectable source is a fluid.

47. The apparatus of claim 44 wherein the sensing means for sensing the source of radiation is a gamma ray detector.

48. The apparatus of claim 43 wherein the detectable source is a magnetic wire.

49. The apparatus of claim 48 wherein the sensing means is a directional variation magnetic field sensor.