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  
         [0001]    1. Field of Invention  
           [0002]    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.  
           [0003]    2. Background of the Invention  
           [0004]    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.  
           [0005]    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 &amp; 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.  
           [0006]    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 &amp; 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.  
           [0007]    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.  
           [0008]    3. Description of Related Art  
           [0009]    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.  
           [0010]    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.  
           [0011]    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  
         [0012]    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  
       [0013]    [0013]FIG. 1 is a fragmentary, partly diagrammatic, partly cross-sectional elevation of a wellbore containing apparatus of the present invention.  
         [0014]    [0014]FIG. 2 is a schematic representation of the apparatus of the present invention.  
         [0015]    [0015]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.  
         [0016]    [0016]FIG. 4 is a cross-sectional view of the apparatus of FIG. 2 through the detection means of the apparatus of the present invention.  
         [0017]    [0017]FIG. 5 is a plan view of the apparatus of FIG. 2 inside the wellbore casing.  
         [0018]    [0018]FIG. 6 is a schematic view of one embodiment of the detectable source of the invention attached to the control means.  
         [0019]    [0019]FIG. 7 is a schematic view of a second embodiment of the detectable source of the invention attached to the control means. 
     
    
     DETAILED DESCRIPTION OF THE INVENTION  
       [0020]    [0020]FIG. 1 discloses a partial sectional view of a cement-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 &amp; 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 .  
         [0022]    [0022]FIG. 2 is an elevation view of 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.  
         [0023]    As shown in FIG. 2, intermediate in 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 .  
         [0024]    Referring to FIGS. 3, 4 and  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.  
         [0025]    [0025]FIG. 5 depicts a plan, cross-section of perforating means  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 .  
         [0026]    Since it is possible to selectively fire perforation means  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.  
         [0027]    In another embodiment of the method of the invention, 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.  
         [0028]    [0028]FIGS. 6 and 7 are schematic diagrams of portions of 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.  
         [0030]    Perforation means  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.  
         [0031]    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.