Patent Publication Number: US-8991245-B2

Title: Apparatus and methods for characterizing a reservoir

Description:
CROSS REFERENCES TO RELATED APPLICATIONS 
     This U.S. National Phase application claims priority to PCT Patent Application No. PCT/US2009/045296, filed May 27, 2009, which is hereby fully incorporated by reference. 
     BACKGROUND 
     Historically, boreholes (also known as wellbores, or simply wells) have been drilled to seek out subsurface formations (also known as downhole reservoirs) containing highly desirable fluids, such as oil, gas or water. A borehole is drilled with a drilling rig that may be located on land or over bodies of water, and the borehole itself extends downhole into the subsurface formations. The borehole may remain ‘open’ after drilling (i.e., not lined with casing), or it may be provided with a casing (otherwise known as a liner) to form a ‘cased’ borehole. A cased borehole is created by inserting a plurality of interconnected tubular steel casing sections (i.e., joints) into an open borehole and pumping cement downhole through the center of the casing. The cement flows out the bottom of the casing and returns towards the surface through a portion of the borehole between the casing and the borehole wall, known as the ‘annulus.’ The cement is thus employed on the outside of the casing to hold the casing in place and to provide a degree of structural integrity and a seal between the formation and the casing. 
     Various techniques for performing formation evaluation (i.e., interrogating and analyzing the surrounding formation regions for the presence of oil and gas) in open, uncased boreholes have been described, for example, in U.S. Pat. Nos. 4,860,581 and 4,936,139.  FIGS. 1A and 1B  illustrate a known formation testing apparatus according to the teachings of these patents. The apparatus A of  FIGS. 1A and 1B  is of modular construction, although a unitary tool is also useful. The apparatus A is a downhole tool that can be lowered into the well bore (not shown) by a wire line (not shown) for the purpose of conducting formation evaluation tests. The wire line connections to tool A as well as power supply and communications-related electronics are not illustrated for the purpose of clarity. The power and communication lines that extend throughout the length of the tool are generally shown at  8 . These power supply and communication components are known to those skilled in the art and have been in commercial use in the past. This type of control equipment would normally be installed at the uppermost end of the tool adjacent the wire line connection to the tool with electrical lines running through the tool to the various components. 
     As shown in the embodiment of  FIG. 1A , the apparatus A has a hydraulic power module C, a packer module P, and a probe module E. Probe module E is shown with one probe assembly  10  which may be used for permeability tests or fluid sampling. When using the tool to determine anisotropic permeability and the vertical reservoir structure according to known techniques, a multiprobe module F can be added to probe module E, as shown in  FIG. 1A . Multiprobe module F has sink probe assembly  14 , and horizontal probe assembly  12 . Alternately, a dual packer module P is commonly combined with the probe module E for vertical permeability tests. 
     The hydraulic power module C includes pump  16 , reservoir  18 , and motor  20  to control the operation of the pump  16 . Low oil switch  22  provides a warning to the tool operator that the oil level is low, and, as such, is used in regulating the operation of the pump  16 . 
     The hydraulic fluid line  24  is connected to the discharge of the pump  16  and runs through hydraulic power module C and into adjacent modules for use as a hydraulic power source. In the embodiment shown in  FIG. 1A , the hydraulic fluid line  24  extends through the hydraulic power module C into the probe modules E and/or F depending upon which configuration is used. The hydraulic loop is closed by virtue of the hydraulic fluid return line  26 , which in  FIG. 1A  extends from the probe module E back to the hydraulic power module C where it terminates at the reservoir  18 . 
     The pump-out module M, seen in  FIG. 1B , can be used to dispose of unwanted samples by virtue of pumping fluid from the flow line  54  into the borehole, or may be used to pump fluids from the borehole into the flow line  54  to inflate the straddle packers  28  and  30 . Furthermore, pump-out module M may be used to draw formation fluid from the wellbore via the probe module E or F, or packer module P, and then pump the formation fluid into the sample chamber module S against a buffer fluid therein. This process will be described further below. 
     The bi-directional piston pump  92 , energized by hydraulic fluid from the pump  91 , can be aligned to draw from the flow line  54  and dispose of the unwanted sample though flow line  95 , or it may be aligned to pump fluid from the borehole (via flow line  95 ) to flow line  54 . The pump-out module can also be configured where flow line  95  connects to the flow line  54  such that fluid may be drawn from the downstream portion of flow line  54  and pumped upstream or vice versa. The pump-out module M has the necessary control devices to regulate the piston pump  92  and align the fluid line  54  with fluid line  95  to accomplish the pump-out procedure. It should be noted here that piston pump  92  can be used to pump samples into the sample chamber module(s) S, including overpressuring such samples as desired, as well as to pump samples out of sample chamber module(s) S using the pump-out module M. The pump-out module M may also be used to accomplish constant pressure or constant rate injection if necessary. With sufficient power, the pump-out module M may be used to inject fluid at high enough rates so as to enable creation of microfractures for stress measurement of the formation. 
     Alternatively, the straddle packers  28  and  30  shown in  FIG. 1A  can be inflated and deflated with borehole fluid using the piston pump  92 . As can be readily seen, selective actuation of the pump-out module M to activate the piston pump  92 , combined with selective operation of the control valve  96  and inflation and deflation of the valves I, can result in selective inflation or deflation of the packers  28  and  30 . Packers  28  and  30  are mounted to outer periphery  32  of the apparatus A, and may be constructed of a resilient material compatible with wellbore fluids and temperatures. The packers  28  and  30  have a cavity therein. When the piston pump  92  is operational and the inflation valves I are properly set, fluid from the flow line  54  passes through the inflation/deflation valves I, and through the flow line  38  to the packers  28  and  30 . 
     As also shown in  FIG. 1A , the probe module E has a probe assembly  10  that is selectively movable with respect to the apparatus A. Movement of the probe assembly  10  is initiated by operation of a probe actuator  40 , which aligns the hydraulic flow lines  24  and  26  with the flow lines  42  and  44 . The probe  46  is mounted to a frame  48 , which is movable with respect to apparatus A, and the probe  46  is movable with respect to the frame  48 . These relative movements are initiated by a controller  40  by directing fluid from the flow lines  24  and  26  selectively into the flow lines  42 ,  44 , with the result being that the frame  48  is initially outwardly displaced into contact with the borehole wall (not shown). The extension of the frame  48  brings the probe  46  adjacent the borehole wall and compresses an elastomeric ring (called a packer) against the borehole wall, thus creating a seal between the borehole and the probe  46 . Since one objective is to obtain an accurate reading of pressure in the formation, which pressure is reflected at the probe  46 , it is desirable to further insert the probe  46  through the built up mudcake and into contact with the formation. Thus, alignment of the hydraulic flow line  24  with the flow line  44  results in relative displacement of the probe  46  into the formation by relative motion of the probe  46  with respect to the frame  48 . The operation of the probes  12  and  14  is similar to that of probe  10 , and will not be described separately. 
     Having inflated the packers  28  and  30  and/or set the probe  10  and/or the probes  12  and  14 , the fluid withdrawal testing of the formation can begin. The sample flow line  54  extends from the probe  46  in the probe module E down to the outer periphery  32  at a point between the packers  28  and  30  through the adjacent modules and into the sample modules S. The vertical probe  10  and the sink probe  14  thus allow entry of formation fluids into the sample flow line  54  via one or more of a resistivity measurement cell  56 , a pressure measurement device  58 , and a pretest mechanism  59 , according to the desired configuration. Also, the flow line  64  allows entry of formation fluids into the sample flow line  54 . When using the module E, or multiple modules E and F, the isolation valve  62  is mounted downstream of the resistivity sensor  56 . In the closed position, the isolation valve  62  limits the internal flow line volume, improving the accuracy of dynamic measurements made by the pressure gauge  58 . After initial pressure tests are made, the isolation valve  62  can be opened to allow flow into the other modules via the flow line  54 . 
     When taking initial samples, there is a high prospect that the formation fluid initially obtained is contaminated with mud cake and filtrate. It is desirable to purge such contaminants from the sample flow stream prior to collecting sample(s). Accordingly, the pump-out module M is used to initially purge from the apparatus A specimens of formation fluid taken through the inlet  64  of the straddle packers  28 ,  30 , or vertical probe  10 , or sink probe  14  into the flow line  54 . 
     The fluid analysis module D includes an optical fluid analyzer  99 , which is particularly suited for the purpose of indicating where the fluid in flow line  54  is acceptable for collecting a high quality sample. The optical fluid analyzer  99  is equipped to discriminate between various oils, gas, and water. U.S. Pat. Nos. 4,994,671; 5,166,747; 5,939,717; and 5,956,132, as well as other known patents, all assigned to Schlumberger, describe the analyzer  99  in detail, and such description will not be repeated herein. 
     While flushing out the contaminants from apparatus A, formation fluid can continue to flow through the sample flow line  54  which extends through adjacent modules such as the fluid analysis module D, pump-out module M, flow control module N, and any number of sample chamber modules S that may be attached as shown in  FIG. 1B . Those skilled in the art will appreciate that by having a sample flow line  54  running the length of the various modules, multiple sample chamber modules S can be stacked without necessarily increasing the overall diameter of the tool. Alternatively, as explained below, a single sample module S may be equipped with a plurality of small diameter sample chambers, for example by locating such chambers side by side and equidistant from the axis of the sample module. The tool can therefore take more samples before having to be pulled to the surface and can be used in smaller bores. 
     Referring again to  FIGS. 1A and 1B , flow control module N includes a flow sensor  66 , a flow controller  68 , piston  71 , reservoirs  72 ,  73  and  74 , and a selectively adjustable restriction device such as a valve  70 . A predetermined sample size can be obtained at a specific flow rate by use of the equipment described above. 
     The sample chamber module S can then be employed to collect a sample of the fluid delivered via flow line  54 . If a multi-sample module is used, the sample rate can be regulated by flow control module N, which is beneficial but not necessary for fluid sampling. With reference to upper sample chamber module S in  FIG. 1B , a valve  80  is opened and one of the valves  62  or  62 A,  62 B is opened (whichever is the control valve for the sampling module) and the formation fluid is directed through the sampling module, into the flow line  54 , and into the sample collecting cavity  84 C in chamber  84  of sample chamber module S, after which valve  80  is closed to isolate the sample, and the control valve of the sampling module is closed to isolate the flow line  54 . The chamber  84  has a sample collecting cavity  84 C and a pressurization/buffer cavity  84   p . The tool can then be moved to a different location and the process repeated. Additional samples taken can be stored in any number of additional sample chamber modules S which may be attached by suitable alignment of valves. For example, there are two sample chambers S illustrated in  FIG. 1B . After having filled the upper chamber by operation of shut-off valve  80 , the next sample can be stored in the lowermost sample chamber module S by opening shut-off valve  88  connected to sample collection cavity  90 C of chamber  90 . The chamber  90  has a sample collecting cavity  90 C and a pressurization/buffer cavity  90   p . It should be noted that each sample chamber module has its own control assembly, shown in  FIG. 1B  as  100  and  94 . Any number of sample chamber modules S, or no sample chamber modules, can be used in particular configurations of the tool depending upon the nature of the test to be conducted. Also, sample module S may be a multi-sample module that houses a plurality of sample chambers, as mentioned above. 
     It should also be noted that buffer fluid in the form of full-pressure wellbore fluid may be applied to the backsides of the pistons in chambers  84  and  90  to further control the pressure of the formation fluid being delivered to the sample modules S. For this purpose, the valves  81  and  83  are opened, and the piston pump  92  of the pump-out module M must pump the fluid in the flow line  54  to a pressure exceeding wellbore pressure. It has been discovered that this action has the effect of dampening or reducing the pressure pulse or “shock” experienced during drawdown. This low shock sampling method has been used to particular advantage in obtaining fluid samples from unconsolidated formations, plus it allows overpressuring of the sample fluid via piston pump  92 . 
     It is known that various configurations of the apparatus A can be employed depending upon the objective to be accomplished. For basic sampling, the hydraulic power module C can be used in combination with the electric power module L, probe module E and multiple sample chamber modules S. For reservoir pressure determination, the hydraulic power module C can be used with the electric power module L and the probe module E. For uncontaminated sampling at reservoir conditions, the hydraulic power module C can be used with the electric power module L, probe module E in conjunction with fluid analysis module D, pump-out module M and multiple sample chamber modules S. A simulated Drill Stem Test (DST) test can be run by combining the electric power module L with the packer module P and the sample chamber modules S. Other configurations are also possible and the makeup of such configurations also depends upon the objectives to be accomplished with the tool. The tool can be of unitary construction a well as modular, however, the modular construction allows greater flexibility and lower cost to users not requiring all attributes. 
     The individual modules of the apparatus A are constructed so that they quickly connect to each other. Flush connections between the modules may be used in lieu of male/female connections to avoid points where contaminants, common in a wellsite environment, may be trapped 
     Flow control during sample collection allows different flow rates to be used. In low permeability situations, flow control is very helpful to prevent drawing formation fluid sample pressure below its bubble point or asphaltene precipitation point. 
     Thus, once the tool engages the wellbore wall, fluid communication is established between the formation and the downhole tool. Various testing and sampling operations may then be performed. Typically, a pretest is performed by drawing fluid into the flow line by selectively activating a pretest piston. The pretest piston is retracted so the fluid flows into a portion of the flow line of the downhole tool. The cycling of the piston through a drawdown and buildup phase provides a pressure trace that is analyzed to evaluate the downhole formation pressure, to determine if the packer has sealed properly, and to determine if the fluid flow is adequate to obtain a diagnostic sample. 
     It follows from the above discussion that the measurement of pressure and the collection of fluid samples from formations penetrated by open boreholes is well known in the relevant art. Once casing has been installed in the borehole, however, the ability to perform such tests is limited. There are hundreds of cased wells which are considered for abandonment each year in North America, which add to the thousands of wells that are already idle. These abandoned wells have been determined to no longer produce oil and gas in necessary quantities to be economically profitable. However, the majority of these wells were drilled in the late 1960&#39;s and 1970&#39;s and logged using techniques that are primitive by today&#39;s standards. Thus, recent research has uncovered evidence that many of these abandoned wells contain large amounts of recoverable natural gas and oil (perhaps as much as 100 to 200 trillion cubic feet) that have been missed by conventional production techniques. Because the majority of the field development costs such as drilling, casing and cementing have already been incurred for these wells, the exploitation of these wells to produce oil and natural gas resources could prove to be an inexpensive venture that would increase production of hydrocarbons and gas. It is, therefore, desirable to perform additional tests on such cased boreholes. 
     In order to perform various tests on a cased borehole to determine whether the well is a good candidate for production, it is often necessary to perforate the casing to investigate the formation surrounding the borehole. One such commercially-used perforation technique employs a tool which can be lowered on a wireline to a cased section of a borehole, the tool including a shaped explosive charge for perforating the casing, and testing and sampling devices for measuring hydraulic parameters of the environment behind the casing and/or for taking samples of fluids from said environment. 
     Various techniques have been developed to create perforations in cased boreholes, such as the techniques and perforating tools that are described, for example, in U.S. Pat. Nos. 5,195,588; 5,692,565; 5,746,279; 5,779,085; 5,687,806; and 6,119,782. 
     The &#39;588 patent by Dave describes a downhole formation testing tool which can reseal a hole or perforation in a cased borehole wall. The &#39;565 patent by MacDougall et al. describes a downhole tool with a single bit on a flexible shaft for drilling, sampling through, and subsequently sealing multiple holes of a cased borehole. The &#39;279 patent by Havlinek et al. describes an apparatus and method for overcoming bit-life limitations by carrying multiple bits, each of which are employed to drill only one hole. The &#39;806 patent by Salwasser et al. describes a technique for increasing the weight-on-bit delivered by the bit on the flexible shaft by using a hydraulic piston. 
     Another perforating technique is described in U.S. Pat. No. 6,167,968 assigned to Penetrators Canada. The &#39;968 patent discloses a rather complex perforating system involving the use of a milling bit for drilling steel casing and a rock bit on a flexible shaft for drilling formation and cement. 
     Despite such advances in formation evaluation and perforating systems, a need exists for a downhole tool that is capable of perforating the sidewall of a wellbore and performing the desired formation evaluation processes. Such a system is also preferably provided with a probe/packer system capable of supporting the perforating tool and/or pumping capabilities for drawing fluid into the downhole tool. It is further desirable that this combined perforating and formation evaluation system be provided with a bit system capable of even long term use, and be adaptable to perform in a variety of wellbore conditions, such as cased or open hole wellbores. It is further desirable that such as system provide a probe/packer assembly that is less prone to the problems of differential sticking of the tool body to the borehole wall, and reduces the risk of damaging the probe assembly during conveyance. It is further desirable that such a system have the ability to perforate a selective distance into the formation, sufficient to reach beyond the zone immediately around the borehole which may have had its permeability altered, reduced or damaged due to the effects of drilling the borehole, including pumping and invasion of drilling fluids. 
     SUMMARY 
     One embodiment of the present disclosure provides an apparatus for characterizing a subsurface formation includes a tool body adapted for conveyance within a borehole penetrating the subsurface formation, a probe assembly carried by the tool body for sealing off a region of the borehole wall, and an actuator for moving the probe assembly between a retracted position and a deployed position. The retracted position is typically used during conveyance of the tool body to the desired position within the borehole and the deployed position is used for sealing off a region of the borehole wall. The apparatus further includes a perforator for penetrating a portion of the sealed-off region of the borehole wall by projecting the perforator through an opening or port in the probe assembly, wherein the perforator penetrates at least one structure such as a consolidated formation, a casing and/or cement. The apparatus further includes a power source disposed in the tool body and operatively connected to the perforator for operating the perforator. The apparatus further includes a flow line extending through a portion of the tool body and fluidly communicating with the perforator, the actuator, the probe assembly, or a combination thereof; and a pump carried within the tool body operatively coupled to the flow line. 
     Another embodiment of the present disclosure provides a method for characterizing a subsurface formation. The method includes the steps of conveying a tool body within a borehole penetrating the subsurface formation to a desired position and sealing off a region of the borehole wall. Specifically, the method includes the steps of a) conveying a tool body within a borehole wherein the tool body carries a probe assembly, an actuator for moving the probe assembly between a retracted position used during conveyance of the tool body and a deployed position used for sealing off a region of the borehole wall, a perforator, a power source disposed in the tool body and operatively connected to the perforator for operating the perforator, and a pump operatively coupled to the flow line, b) sealing off a region of the borehole wall using the probe assembly, and c) projecting the perforator through an opening or port in the probe assembly for penetrating a portion of the sealed-off region of the borehole wall using the power source, wherein the perforator penetrates at least one of a consolidated formation, casing and cement. 
     In another embodiment, the method further comprises pumping fluid in the flow line using the pump. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       So that the above recited features and advantages of the present disclosure can be understood in detail, a more particular description, briefly summarized above, may be had by reference to the embodiments thereof that are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments and are therefore not to be considered limiting of its scope. 
         FIGS. 1A-1B  are schematic illustrations of a prior art formation tester for use in open hole environments. 
         FIG. 2  is a schematic illustration of a prior art formation tester for use in cased hole environments. 
         FIG. 3  is schematic illustration of an improved formation tester for use in open hole or cased hole environments in accordance with the present disclosure. 
         FIGS. 4A-4B  are detailed sequential illustrations, partially in section, of one embodiment of a deployable probe assembly in accordance with one aspect of the present disclosure. 
         FIGS. 5A-5B  are detailed sequential illustrations, partially in section, of a second embodiment of the deployable probe assembly. 
         FIGS. 6A-6B  are detailed sequential illustrations, partially in section, of a third embodiment of the deployable probe assembly. 
         FIG. 7  is a detailed illustration, partially in section, of a fourth embodiment of the deployable probe assembly. 
         FIG. 8  is a schematic illustration of an improved formation tester employing dual inflatable packers in accordance with another aspect of the present disclosure. 
         FIGS. 9A ,  9 B, and  9 C are detailed sequential illustrations, partially in section, of one embodiment of a dual bit configuration for perforating the walls of a cased hole in accordance with another aspect of the present disclosure. 
         FIGS. 10A ,  10 B, and  10 C are detailed sequential illustrations, partially in section, of a second embodiment of the dual bit configuration for perforating the walls of a cased hole. 
         FIGS. 11A ,  11 B, and  11 C are detailed sequential illustrations, partially in section, of a third embodiment of the dual bit configuration for perforating the walls of a cased hole. 
         FIGS. 12A ,  12 B, and  12 C are detailed sequential illustrations, partially in section, of a fourth embodiment of the dual bit configuration for perforating the walls of a cased hole. 
         FIG. 13  is a schematic illustration of a tool string in which an improved formation tester in accordance with the present disclosure may be implemented for use in open hole or cased hole environments. 
         FIG. 14  is a pressure graph that may be acquired while performing a stress or fracture test performed at a perforation of the walls of an open hole or a cased hole. 
         FIGS. 15A and 15B  are respectively a front perspective illustration and a top side cross section illustration of a stress or fracture test that may be performed with the formation tester of  FIG. 13 . 
         FIG. 16  is a graph illustrating a method for determining the maximum and minimum horizontal stresses in the formation and their orientations. 
     
    
    
     DETAILED DESCRIPTION 
       FIG. 2  depicts a perforating tool  212  for formation evaluation. The tool  212  is suspended on a cable  213 , inside steel casing  211 . This steel casing sheathes or lines the borehole  210  and is supported with cement  210   b . The borehole  210  is typically filled with a completion fluid or water. The cable length substantially determines the depths to which the tool  212  can be lowered into the borehole. Depth gauges can determine displacement of the cable over a support mechanism (e.g., sheave wheel) and determines the particular depth of the logging tool  212 . The cable length is controlled by a suitable known means at the surface such as a drum and which mechanism (not shown). Depth may also be determined by electrical, nuclear or other sensors which correlate depth to previous measurements made in the well or to the well casing. Also, electronic circuitry (not shown) at the surface represents control communications and processing circuitry for the logging tool  212 . The circuitry may be of known type and does not need to have novel features. 
     The tool  212  of  FIG. 2  is shown having a generally cylindrical body  217  equipped with a longitudinal cavity  228  which encloses an inner housing  214  and electronics. Anchor pistons  215  force the tool-packer  217   b  against the casing  211  forming a pressure-tight seal between the tool and the casing and serving to keep the tool stationary. 
     The inner housing  214  contains the perforating means, testing and sampling means and the plugging means. This inner housing is moved along the tool axis (vertically) through the cavity  228  by the housing translation piston  216  secured to a portion of the body  217  but also disposed within the cavity  228 . This movement of the inner housing  214  positions, in the respective lower-most and upper-most positions, the components of the perforating and plugging means in lateral alignment with the lateral body opening  212   a  within the packer  217   b . Opening  212   a  communicates with the cavity  228  via an opening  228   a  into the cavity. 
     A flexible shaft  218  is located inside the inner housing and conveyed through a tubular guide channel  214   b  which extends through the housing  214  from the drive motor  220  to a lateral opening  214   a  in the housing. A drill bit  219  is rotated via the flexible shaft  218  by the drive motor  220 . This motor is held in the inner housing by a motor bracket  221 , which is itself attached to a translation motor  222 . The translation motor moves drive motor  220  by turning a threaded shaft  223  inside a mating nut in the motor bracket  221 . The flex shaft translation motor thus provides a downward force on the drive motor  220  and the flex shaft  218  during drilling, thus controlling the penetration. This drilling system allows holes to be drilled which are substantially deeper than the tool diameter, but alternative technology (not shown) may be employed if necessary to produce perforations of a depth somewhat less than the diameter of the tool. 
     For the purpose of taking measurements and samples, a flow line  224  is also contained in the inner housing  214 . The flow line is connected at one end to the cavity  228 —which is open to formation pressure during perforating—and is otherwise connected via an isolation valve (not shown) to the main tool flow line (not shown) running through the length of the tool which allows the tool to be connected to sample chambers. 
     A plug magazine (or alternatively a revolver)  226  is also contained in the inner housing  214 . After formation pressure has been measured and samples taken, the housing translation piston  216  shifts the inner housing  214  to move the plug magazine  226  into position aligning a plug setting piston  225  with openings  228   a ,  212   a  and the drilled hole. The plug setting piston  225  then forces one plug from the magazine into the casing, thus resealing the drilled hole. The integrity of the plug seal may be tested by monitoring pressure through the flow line while a “drawdown” piston is actuated. The resulting pressure should drop and then remain constant at the reduced value. A plug leak will be indicated by a return of the pressure to formation pressure after actuating the drawdown piston. It should be noted that this same testing method is also used to verify the integrity of the tool-packer seal before drilling commences. The sequence of events is completed by releasing the tool anchors. The tool is then ready to repeat the sequence. 
       FIG. 3  depicts a downhole formation evaluation tool  300  positioned in an open hole wellbore. The tool includes a body  301  adapted for conveyance within a borehole  306  penetrating the subsurface formation  305 . The tool body  301  is well adapted for conveyance within a borehole via a wireline W, in the manner of conventional formation testers, but is also adaptable for conveyance within a drillstring (i.e., conveyed while drilling). The apparatus is anchored and/or supported against the side of the borehole wall  312  opposite a probe assembly  307  by actuating anchor pistons  311 . 
     The probe assembly (also referred to as simply “probe”)  307  is carried by the tool body  301  for sealing off a region  314  of the borehole wall  312 . A piston actuator  316  is employed for moving the probe assembly  307  between a retracted position (not shown in  FIG. 3 ) for conveyance of the tool body and a deployed position (shown in  FIG. 3 ) for sealing off the region  314  of the borehole wall  312 . The actuator of this embodiment preferably includes a plurality of pistons connected to the probe assembly  307  for moving the probe between retracted and deployed positions, and a controllable energy source (preferably a hydraulic system) for powering the pistons. The probe assembly  307  preferably includes a compressible packer  324  mounted to a piston-deployed plate  326  to create the seal between the borehole wall  312  and the formation of interest  305 . 
     A perforator, including a flexible drilling shaft  309  equipped with drill bit  308  and driven by a motor assembly  302 , is employed for penetrating a portion of the sealed-off region  314  of the borehole wall  312  bounded by the packer  324 . The flexible shaft  309  conveys rotational and translational power to the drill bit  308  from the drive motor  302 . The action of the perforator results in lateral bore or perforation  310  extending partially through the formation  305 . 
     The tool  301  further includes a flow line  318  extending through a portion of the tool and fluidly communicating with the formation  305 , via perforation  310 , by way of the perforator pathway  320  and the pathway  322  defined by the actuator and the packer (both pathways considered to be extended components of the flow line  318 ) for admitting formation fluid into the tool body  301 . A pretest piston  315  is also connected to flow line  320  to perform pretests. 
     A pump  303  is also carried within the tool body for drawing formation fluid into the tool body via the flow line  318  and the pathway  320 . A sample chamber  321  is further carried within the tool body  301  for receiving formation fluid from the pump  303 . Additionally, instruments may be carried within the tool body  301  for measuring pressure, and for analyzing formation fluid drawn into the tool body (e.g., like optical fluid analyzer  99  from  FIG. 1 ) via the flow line  318  and the pump  303 . The pump  303  may be of similar construction to the pump  92  of  FIG. 1A . Further, the tool  300  may be of modular construction, and the pump  303  may be implemented in a pump-out module similar to the pump-out module M of  FIG. 1A . In particular, the pump  303  may be implemented with a bi-directional piston pump, energized by hydraulic fluid from a hydraulic pump (not shown). The pump  303  is aligned to draw a formation fluid sample from the pathway  320  and dispose of an unwanted portion of the formation fluid sample in the wellbore via a dump flow line (not shown), or it may be reversed to pump fluid from the borehole (via the dump flow line) into the pathway  320 . In the later case, the tool  300  may be used to inject wellbore fluid in the formation though the perforation  310  extending partially through the formation  305 . With adequate power, the pump  303  may be used to inject wellbore fluid at sufficiently high rates to enable creation of fractures for stress measurement of the formation, as further detailed thereafter. 
     It should be noted here that the pump  303  can be used to pump samples into the sample chamber  321  as mentioned above, including overpressuring such samples as desired. In addition, the pump  303  may be used to pump samples out of sample chamber  321 . In that case, the sample chamber  321  may be adapted for conveying an injection fluid in the borehole  306 . The injection fluid may be disposed in the sample chamber  321  at the surface, before lowering the tool  300  in the wellbore  306 . Alternatively, the injection fluid may be collected downhole, for example by collecting a formation fluid at a different depth (e.g. gas from the top a reservoir, water from the bottom of a reservoir, etc.) The pump  303  may be provided with control devices useful to accomplish constant pressure or constant rate injection if desirable. 
     Once the perforation(s) or hole(s)  310  have been created, the flow line  318  can freely communicate formation fluid to these components for downhole evaluation and/or storage. The pump  303  is not essential, but is quite useful for controlling the flow of formation fluid through the flow line  318 . Formation evaluation and sampling may occur at multiple hole-penetration depths by drilling further into the formation  305 . Preferably, such a hole extends through the damaged zone surrounding the borehole  306  and into the connate fluid zone of the formation  305 . 
     Turning now to  FIGS. 4A-4B , an alternate formation evaluation tool  400  is depicted.  FIG. 4A  shows the probe assembly  407  in the retracted position for conveyance of the tool  400 .  FIG. 4B  shows the probe assembly  407  moving towards the extended position for sealing off a region of the borehole wall  412 . The tool  400  employs a perforator that includes at least one flexible drilling shaft  409  equipped with a drill bit  408  at an end thereof for penetrating a portion of the sealed-off region  414  of the borehole wall  412  (and casing and cement if present). It is preferred that the drill bit  408  of this embodiment be made from diamond for open-hole use, but will preferably employ other materials (e.g., tungsten carbide) for cased-hole use (described in detail below), which improves the ability to penetrate the formation  405  to a desired lateral depth. A drilling motor assembly  402  is provided for applying torque and translatory force to the drilling shaft  409 . The perforator of this embodiment further includes a semi-rigid tubular guide  420  for directing the translatory path of the flexible drilling shaft  409 , so as to effect a substantially normal penetration path by the drill bit through the borehole wall  412 . 
     As illustrated by the sequence of  FIGS. 4A-4B , the tubular guide  420  is semi-flexible, permitting it to flex and move with the deployment of the probe assembly  407 . The hydraulically-induced force of the pistons  416  deploy and compresses the packer element  424  against the wall  412  of the borehole  405 . The tubular guide  420  is connected at one end to the drilling motor assembly  402 , and is connected at another end to the probe assembly  407 . The tubular guide  420  serves two purposes. First, it provides sufficient rigidity to impose a reactive force on the flexible shaft  409  that permits the shaft to move under the force provided by the drive motor  402 . Second, the tubular guide  420  connects a flow line (not shown in  FIGS. 4A-4B ) in the apparatus  400  to probe plate  426 , and thus acts as an extension of the tool&#39;s flow line. 
       FIGS. 5A-5B  depict another alternate formation evaluation tool  500  conveyed within a borehole penetrating a formation  505 .  FIG. 5A  shows the probe assembly  507  in the retracted position.  FIG. 5B  shows the probe assembly  507  moving towards the extended position for engagement with the wellbore wall. The tool includes a tubular guide  520  defined by a channel extending through a portion of the tool body  501 . In this alternative embodiment, the tubular guide includes a laterally-protuberant portion  530  of the tool body  501  through which a portion of the guide-defining channel extends. In this manner, bit  508  at the end of the flexible drilling shaft  509  is guided through the central opening in the probe assembly  507  towards the borehole wall  512 . A bellows  535  is used to fluidly connect the tubular guide  520  (which serves as part of a flow line within the tool) in the tool body  500  to the probe assembly  507  as the probe assembly is deployed by the action of hydraulic pistons  516  on probe plate  526 , compressing packer element  524  against the wall  512  of the formation  505  to seal off the region  514 . 
     A further alternative formation evaluation tool  600  being conveyed in a borehole penetrating a formation  605  is illustrated in  FIGS. 6A-6B .  FIG. 6A  shows a probe assembly  607  in the retracted position, while  FIG. 6B  shows the probe assembly  607  moving to the extended position for engagement with the wellbore wall  612 . Pistons  616  are provided to extend and retract the probe assembly  607 . A tube guide  620  includes a substantially rigid tubular portion  632  of the probe assembly  607  that is concentric with a portion of the channel  621  that substantially defines the tubular guide  620 . The tubular portion  632  may be used to fluidly connect the tool body  601  (more particularly, tubular guide  620 ) to the probe assembly  607 . Thus, when pistons  616  deploy the probe plate  626  towards the borehole wall  612  so as to compress the packer element  624  and seal of a region  614  (see  FIG. 6B ) the perforation (not shown) formed by flexible shaft  609  and drill bit  608  conducts fluid from the formation  605  to the tool  600 . The tubular portion  632  is preferably flexible so as to bend as the probe assembly  607  is deployed, such that the tubular portion  632  maintains physical engagement with the lateral protuberant portion  630  of the tool body  601 , thereby maintaining the fluid connection with the tool body  601 . The addition of a spherical joint (not shown) between the sliding tubular portion  632  and the probe plate  626  may reduce the preference of the sliding tubular portion  632  to be bendable. 
       FIG. 7  depicts another alternate formation evaluation tool  700  including a tool body  701  conveyed in a borehole penetrating a formation  705 . This alternative is similar to that of  FIGS. 6A-6B , in that a tubular guide  720  includes a substantially rigid tubular portion  732  of a probe assembly  707  that is concentric with a portion of the channel  721  that substantially defines the tubular guide  720 . The primary differences here are that the probe plate  726  is relatively narrow, and the rigid tubular portion  732  of the probe assembly  707  also serves as an actuator piston (see annular protuberance  734  within hydraulically-pressurized annulus  736 ).  FIG. 7  also shows an anchoring system  711  for positioning and supporting the tool  700  within the borehole. One further difference is the use of a separate flow line  780  that is connected at one end thereof to a cavity  770  within which the probe portion  732  is reciprocated. The flow line  780  is otherwise connected via an isolation valve (not shown) to the main tool flow line (not shown) running through the length of the tool which allows the tool to be connected to sample chambers. Thus, in this embodiment, the tubular guide  720  does not serve as a means for sampling formation fluid (although the tubular guide may experience formation pressure). 
       FIG. 8  depicts another alternate formation evaluation tool  800  disposed in a borehole  812  penetrating a formation  805 . In this embodiment, the probe assembly  807  includes a pair of inflatable packers  824  each carried about axially-separated portions of the tool body  801 . The packers  824  are well adapted for sealingly engaging axially-separated annular regions of the borehole wall  812 . In this embodiment, the actuator for the assembly  800  includes a hydraulic system (not shown) for selectively inflating and deflating the packers  824 . 
       FIG. 8  further illustrates an alternative perforator having utility in the present disclosure. Thus, explosive charge  809  is useful for creating a perforation  810  in the formation  805 . Other suitable perforating means include a hydraulic punch and a coring bit, either of which are useful for creating perforations through the borehole wall. Thus, the embodiment shown is effective for admitting formation fluid into flow line  818  for collection in a sample chamber  811  with the aid of a pump  803 . 
       FIGS. 9-12  depict alternative versions of a dual drill bit assembly usable in connection with perforating tools, such as the perforating tools of  FIGS. 2 and 3 . As shown in  FIG. 9A , the dual bit assembly may be used to penetrate the wall  912  of a borehole  906  penetrating a subsurface formation  905 . The borehole  906  may be equipped with a casing string  936  secured by concrete  938  filling the annulus between the casing and the borehole wall. An anchor system  911  is carried by the tool  900  for supporting the tool within the cased borehole  906 , or more particularly within the casing string  936 . 
     An embodiment of the dual drill bit perforating assembly  970  is shown in  FIGS. 9A-9C  as including a tool body  900  adapted for conveyance within a borehole, such as the cased borehole  906  having a borehole wall  912 .  FIG. 9A  depicts the dual bit system in the retracted position for conveyance within a borehole.  FIG. 9B  depicts the system in a first drilling configuration.  FIG. 9C  depicts the system in a second drilling configuration. This apparatus uses a dual bit system to drill successive, collinear holes through the sidewall  912  of the borehole and the formation (essentially rock) together with casing and cement if present. A first drilling shaft  909   a  has a first drill bit  908   a  connected to an end thereof. The first bit is preferably suited for perforating a portion of the steel casing  936  lining the borehole wall  912 . A second drilling shaft  909   b , which is flexible, has a second drill bit  908   b  connected to an end thereof. The second drill bit is preferably suited for extending through a perforation formed in the casing  936  and perforating the concrete layer  938  and a portion of the formation  905 . A drilling motor assembly (not shown) is employed for applying torque and translatory force to the first and second drilling shafts  909   a ,  909   b.    
     A mechanism, in the form of a coupling assembly  950 , provides the means by which both drilling shafts  909   a ,  909   b  can be driven from a single motor drive. The coupling assembly includes a set of engaging spur gears  940 ,  942 , an intermediate shaft  944 , and a right-angle gear box  946 . The coupling assembly is useful for selectively coupling the drilling motor assembly to the first and second drilling shafts. The second drilling shaft  909   b  is selectively operatively connected to the gear train whereby torque applied to the second drilling shaft  909   b  by the drilling motor assembly is preferably not transferred through the coupling gear train  950  to the first drilling shaft  909   a  unless the second drilling shaft  909   b  is retracted sufficiently to dispose the second drill bit  908   b  into engagement with the spur gear  942 . 
     Thus, for example, for drilling through the steel casing, the second (flexible) drilling shaft  909   b  may be retracted within the tubular guide  920  until the second drill bit  908   b  engages spur gear  942 , as shown in  FIG. 9B . This engagement induces rotation of intermediate rotary shaft  944 . This rotary shaft in turn drives the first drilling shaft  909   a , through the right angle gear mechanism  946 . The first drilling shaft  909   a  is mechanically coupled to the first drill bit  908   a , which is preferably a carbide bit suitable for drilling steel. A hydraulic piston (not shown) may be employed with a thrust bearing to increase the weight on bit to a level necessary to drill the steel casing  936 . 
     Once the casing has been perforated, the concrete layer  938  and the formation  905  are drilled by reversing the direction of the translation motor to retract the first drilling shaft  909   a  and/or by retracting the hydraulic piston (if provided). This retraction step creates enough room for the second (flexible) drilling shaft  909   b  to be inserted through the hole in the casing  936 , as shown in  FIG. 9C . The flexible shaft then continues the drilling operation through the cement layer  938  and steel casing  936 , under the torque and translatory driving force provided by the drive motor system. 
       FIGS. 10A-10C  show another embodiment of the dual bit perforating system  1070 .  FIG. 10A  depicts the dual bit system in the retracted position for conveyance within a borehole.  FIG. 10B  depicts the system in a first drilling configuration.  FIG. 10C  depicts the system in a second drilling configuration. In these figures, the second drilling shaft  1009   b  has a defined drilling path defined by tubular guide  1020   b , and the coupling assembly includes a bit coupling  1008   c  connected to an end of the first drilling shaft  1009   a  opposite the first drill bit  1008   a . A means is provided for selectively moving the first drilling shaft  1009   a  between a holding position in tubular guide  1020   a  (see  FIGS. 10A and 10C ) and a drilling position in tubular guide  1020   b  (see  FIG. 10B ). The drilling position is located in the drilling path (i.e., tubular guide  1020   b ) of the second drilling shaft  1009   b , thereby enabling the second drill bit  1008   b  (which is specially designed for engagement) to engage the bit coupling  1008   c  and drive the first drilling shaft  1009   a.    
     The moving means may move the first drilling shaft by a pivoting motion as shown in the dual bit perforating system  1070  of  FIGS. 10A-10C  or by a translatory motion as shown in the dual bit perforating system  1170  of  FIGS. 11A-11C . A hydraulic piston-assist mechanism, as mentioned above, can be used here as well to provide the appropriate weight-on-bit for the casing drilling operation, and can be further used as the moving means. Thus, the hydraulic mechanism can be used to retract (by pivoting or translation) the first drilling shaft assembly  1109   a  back into the tool body  1103 , and out of the way  1120   b  of the second drilling shaft  1109   b  and back to the holding position  1120   a . Then, the second drilling shaft  1109   b  and second drill bit  1108   b  are free to translate and rotate through pathway  1120   b  so as to drill through the formation rock. 
       FIGS. 12A-12C  depict another dual bit perforating system  1270  including tool body  1203 . In these figures, the first and second drilling shafts  1209   a ,  1209   b  each have respective defined drilling paths  1220   a ,  1220   b . Here, the coupling assembly includes a bit coupling  1208   c  connected to an end of the first drilling shaft  1209   a  opposite the first drill bit  1208   b , and a means including a whipstock  1250  for selectively moving the second drilling shaft  1209   b  from its drilling path  1220   b  to the drilling path  1220   a  of the first drilling shaft  1209   a . This has the effect of positioning the second drill bit  1208   b  for engagement with the bit coupling  1208   c , whereby the second drilling shaft  1209   b  drives the first drilling shaft  1209   a . In other words, the specially designed rock bit on the end of the flexible shaft  1209   b  interfaces with the bit coupling  1208   c  on the end of the casing bit shaft  1209   a . Thus, a rotary motion of the casing bit  1208   a  is applied by rotation of the second (flexible) drilling shaft  1209   b.    
     The casing drilling shaft  1209   a  is preferably mechanically connected to a hydraulic assist mechanism (not shown). The hydraulic assist mechanism provides the required weight-on-bit for the casing drilling operation, and retracts the casing bit assembly back into the tool body  1200  when required. When drilling the steel casing, the tool  1200  is translated downwardly (see FIG.  12 B) to ensure the second drilling shaft enters the first drilling path, via the whipstock  1250 , at the proper elevation. When drilling the formation rock, the tool  1200  is translated upwardly (see  FIG. 12C ) to ensure the second drilling shaft enters the second drilling path  1220   b  at the proper elevation, at which time the second drilling shaft  1209   b  and second drill bit  1208   b  are free to begin drilling rock via drilling path  1220   b.    
     The above dual bit embodiments may require an additional mechanical operation to position the steel bit  1208   a  in the lower position ( FIG. 12B ) for drilling steel and for moving the first drilling shaft  1209   a  upwardly and out of the way ( FIG. 12C ) for drilling the formation. This mechanical operation could be accomplished by the addition of selected hydraulic components—e.g., additional solenoids and hydraulic lines to the existing systems—that are within the level of ordinary skill in the relevant art. 
       FIG. 13  depicts a schematic of a tool string  1300  in which an improved formation tester in accordance with the present disclosure may be implemented for use in open hole or cased hole environments. As shown, the tool string  1300  may be lowered in a borehole  1322 , having a casing  1320  which is supported by the formation via a cement sheath  1321 . However, the tool string  1300  may alternatively be deployed in an uncased or open borehole. The tool string  1300  may be suspended in the borehole  1322  via a wireline cable (not shown) and a logging head (not shown). Alternative conveyance means includes lowering the tool string  1300  via a drill string, or any other conveyance means known in the art. 
     To provide vertical support to the tool and to fix a top portion  1302  of the tool string  1300  to the wellbore wall so that a bottom portion  1305  of the tool string  1300  can be rotated with respect to the formation, the tool string  1300  comprises a wireline anchor  1310 . The wireline anchor  1310  can selectively be extended into frictional engagement with the casing  1320  (or a wall of the wellbore  1322  in the cases the tool string  1300  is deployed in an open borehole). To orient or align the bottom portion  1305  of the tool string  1300  with a desired orientation, the tool string  1300  comprises a powered orienting sub  1311  comprising an electrical motor affixed to the top portion  1302  of the tool string and in particular to the wireline anchor  1310 , the electrical motor being operatively coupled to a shaft affixed to the bottom portion  1305  of the tool string. To provide rotary movement between the top portion and bottom portion of the tool string  1300 , the tool string  1300  comprises a swivel  1312 , through which the motor shaft is disposed. The swivel is configured to permit the bottom part  1302  of the tool string to be turned at any angle relative to the wireline anchor  1310 . To facilitate setting the probe and sealingly engaging a region of the borehole wall adjacent to one side of the tool body while supporting the tool body against a region of the casing (or the borehole wall) opposite the one side of the tool body, the tool string  1300  includes a flex joint  1313  configured to permit non coaxial alignment between the top portion  1302  and the bottom portion  1305  of the tool string. 
     To measure the deviation of the bottom portion  1305  of the tool string, and/or the azimuth of the bottom portion  1305  relative to a fixed reference (e.g. the Earth magnetic field), the tool string  1300  includes an inclinometry device  1314 . The inclinometry device  1314  may be implemented with device similar to a GPIT tool, provided by Schlumberger Technology Corporation. The bottom portion  1305  of the tool string  1300  also includes a formation tester  1315 , which may be similar to the formation evaluation tool  300  described in  FIG. 3 , or any other formation tester described therein. 
     While the tool string  1300  has been described as including an anchor  1310 , a powered orientating sub  1311 , a swivel  1312 , and a flex joint  1313 , alternate implementations may be used wherein one or more of these components is omitted or duplicated in the downhole tool string. For example, such components may be omitted if the formation evaluation tool  1315  is conveyed via a drill string (not shown). 
     In operation, the formation tester  1315  is used to create a perforation  1323 , wherein the perforation penetrates at least one structure such as a consolidated formation, casing or cement. This enables the formation surrounding the perforation to be tested. For example, a pump or a pretest piston (not shown) can be used to pump samples out of a sample chamber (not shown) disposed in the formation tester  1315 . Additionally, instruments may be carried within the formation tester  1315  for measuring pressure, temperature, or flow rate of formation fluid drawn into the tool body or injection fluid injected into the formation. As shown in  FIG. 13 , the formation tester  1315  may be used to inject wellbore fluid from the borehole into the formation though the perforation  1323 . With adequate power, the wellbore fluid may be injected at a sufficient rates for initiating and propagating a fracture  1325 . Where the formation tester  1315  is lowered within an open hole, the perforation  1323  should extent sufficiently deep into the formation so that the created fracture  1325  does not communicate with an unsealed portion of the wellbore  1322 . Alternatively, the formation tester  1315  may be implemented using the formation tester  800  described in  FIG. 8 . 
       FIG. 14  is a pressure graph that may be acquired while performing a stress or fracture test at a perforation of the wall(s) of an open hole or a cased hole. Specifically,  FIG. 14  shows a typical pressure curve  1400  that may be observed when testing a formation. 
     One or more selected fluids may first be controllably injected through the perforation  1323  until a desired pressure level  1410  higher than the formation pressure is obtained. Once this pressure level is achieved, the fluid injection may be stopped and the pressure drop monitored during a leak-off test. The results of the leak-off test may be analyzed to determine mobility of the injected fluid into the formation and/or permeability of the formation. In the case the formation tester  1315  is lowered into the wellbore, the leak-off test results may provide an indication of the integrity of the bond between the casing  1320  and the cement  1321 , and between the cement  1321  and the formation. Indeed, if high injection flow rates do not result in a significant increase of the pressure level  1410  above the formation pressure, the cement may not be adequately bonded. The results of the leak-off test (e.g. the injected fluid mobility) may further be used for estimating a pumping rate for initiating and/or propagating a fracture into the formation. 
     After the leak-off test is terminated, the injection may be restarted and continued until a breakdown pressure  1411  is achieved and the fracture  1425  is initiated at the perforation  1423 . At this point, the fracture  1425  typically propagates rapidly and the pressure drops to the fracture propagation pressure  1412 , a pressure level characteristic of the formation being tested. It should be appreciated that the breakdown pressure  1411  is usually significantly higher than the pressure required for propagating the fracture  1412 . For example the breakdown pressure is in some cases increased by the drilling process in the vicinity of the borehole, as such drilling process sometimes promotes the clogging or cementing of the porosity by mud solids. Drilling a small hole or perforation  1423  past the zone affected by the drilling process may facilitate initiating the fracture at a reduced breakdown pressure. 
     Thus, the formation tester of the present disclosure may be used to advantage for initiating fracture where other formation testers would fail to increase the pressure in the sealed interval sufficiently to initiate the fracture, due to pump operating limitations such as maximum differential pressure, maximum flow rate, and the like. 
     To control the propagation of the fracture  1325 , the injection may advantageously be performed with a pre-test piston, allowing a better control of the fluid injected volume and/or the injection flow rate. For example, the injection flow rate may be interrupted at any time after the fracture has been initiated, and the initial shut in pressure (ISIP)  1413  may be determined. As known in the art, the ISIP value is higher than the fracture closure pressure  1414 , which in turn is indicative of the formation stress normal to the fracture propagation plane. A second injection cycle may be initiated to further propagate the fracture. In that case, the injection flow rate may be increased above the propagation pressure (see pressure data point  1420 ) a number of times as desired to extend the fracture  1325 . For example, the ISIP measurement may be repeated and its evolution with the injected volume may be quantified. An additional advantage of the formation tester  1315  as shown implemented in the tool string  1300  on  FIG. 13  is that the fracture  1325  propagates, at least initially, in a plane that is aligned with the perforation  1323 . Thus, when measuring the ISIP at the early stage of the propagation, it is possible to determine a level of formation stress normal to fracture planes selectively oriented by the orientation of the perforation  1323 , as further detailed in  FIGS. 15A and 15B . 
       FIGS. 15A and 15B , respectively, show a front perspective illustration and a top side cross section illustration of a stress or fracture test that may be performed with the formation tester of  FIG. 13 . In particular, the tool string  1300  shown in  FIG. 13  may be used to perform a plurality of stress or fracture tests at a predetermined depth in the wellbore  1500 . The depth may be determined from open hole logs to identify a formation of interest and/or cased hole logs to identify a zone having a likely integer bond between cement and casing and cement and formation thereby permitting a stress test to be performed. 
     Referring to  FIGS. 15A and 15B , six perforations  1520  are drilled sequentially in the formation  1505  in essentially the same plane. Where the tool string  1300  is used in a cased hole, the perforation preferably penetrates a casing  1507  and a cement sheath  1503 . After each hole is drilled, a fracture is initiated in that hole and propagated (only one fracture  1530  is depicted for clarity in  FIG. 15  A). The pumping used to inject fracturing fluid is stopped and a closure stress  1414  is determined by methods well known in the industry. After the closure stress has been determined, the hole may be plugged if desired and the formatin tester  1315  rotated. The fracturing test is then repeated for a new perforation  1520 . Preferably, the perforations  1520  are positioned sufficiently apart so that any mutual interference is negligible and does not result in substantial error in the estimated closure stress for each fracture. The perforation orientation θ of each perforation is measured using the inclinometry device  1314  with respect to a fixed reference (depicted as the x and y coordinate system in  FIG. 15A ). The closure stress  1414  measured at a particular depth (or a cluster of depths) as a function of the perforation orientation may be used to determine the values minimum and the maximum horizontal stresses in the formation  1505 , respectively depicted as  1510  and  1511  in  FIG. 15B . Further, the minimum and maximum horizontal stress direction may also be determined, as further detailed in  FIG. 16 . 
       FIG. 16  is a graph illustrating a method for determining the maximum and minimum horizontal stress values (respectively  1610  and  1611 ) in the formation and their orientations. In particular,  FIG. 16  shows multiple data points  1620  that are obtained from measured closure stresses as shown in  FIG. 14  (see e.g. closure stresses levels  1412  and  1420  measured at one perforation). The data points  1620  comprise an abscissa equal to two times the perforation orientation θ, and an ordinate equal to the measured closure stress at that perforation orientation. In  FIG. 16 , the data points  1620  are wrapped over a 360° angle interval. A curve  1600  is obtained by fitting a sinusoid to the data points  1600 , and represents a closure stress as a function of two times the perforation orientation θ. The maximum and minimum horizontal stress values (respectively  1610  and  1611 ) are obtained from the maximum and minimum values of the curve  1600 , respectively. The stress orientation relative to the reference is obtained from the abscissa coordinate of the maximum and minimum values divided by two. 
     While specific embodiment involving fracture and/or stress test have been disclosed, injection as understood herein is not limited to fracture and/or stress determination. 
     In view of all of the above, and the figures, those skilled in the art will recognize that the present disclosure introduces an apparatus comprising: a downhole tool configured for conveyance within a borehole penetrating a subterranean formation, wherein the downhole tool comprises: a probe assembly configured to seal a region of a wall of the borehole; a perforator configured to penetrate a portion of the sealed region of the borehole wall by projecting through the probe assembly; a fluid chamber comprising a fluid; and a pump configured to inject the fluid from the fluid chamber into the formation through the perforator. The pump may be configured to inject the fluid from the fluid chamber into the formation through the perforator after the perforator has penetrated the portion of the sealed region of the borehole wall and before the perforator has been removed from the penetrated portion of the sealed region of the borehole wall. The perforator may be configured to penetrate at least one of a consolidated formation, a casing, and cement. The downhole tool may further comprise a tool body housing at least a portion of the probe assembly, the perforator, the fluid chamber, and the pump, and the tool body may be configured for conveyance within the borehole via at least one of a wireline and a drillstring. The downhole tool may further comprise an anchor system configured to support the tool body against a region of the borehole wall opposite the sealed region the borehole wall. The downhole tool may further comprise an actuator configured to move the probe assembly between a retracted position and a deployed position, wherein the probe assembly is configured to seal the region of the borehole wall when in the deployed position. The probe assembly may comprise a substantially rigid plate and a compressible packer element coupled to the plate, and the actuator may comprise: a plurality of pistons connected to the plate and configured to move the probe assembly between the retracted and deployed positions; and a controllable energy source configured to power the pistons. The perforator may comprise: a shaft; a drill bit; and means for applying torque and translatory force to the shaft to project the drill bit through the probe assembly into the sealed region of the borehole wall. The downhole tool may further comprise an inclinometry device configured to measure a perforation orientation. The downhole tool may further comprise: means for measuring a closure stress; and means for determining at least one of a minimum horizontal stress value, a maximum horizontal stress value, and a horizontal stress orientation relative to a reference, based on the measured closure stress. The downhole tool may further comprise means for determining formation permeability based on at least one of the injected fluid and a result of the fluid injection. The downhole tool may further comprise means for determining mobility of the fluid injected into the formation. 
     The present disclosure also introduces a method comprising: conveying a downhole tool within a borehole penetrating a subterranean formation, wherein the downhole tool comprises a probe assembly, a perforator, and a fluid chamber; sealing a region of a wall of the borehole wall using the probe assembly; projecting the perforator through the probe assembly to penetrate a portion of the sealed region of the borehole wall; and injecting fluid from the fluid chamber into the formation through the perforator. Injecting the fluid from the fluid chamber into the formation through the perforator may be performed after the perforator has penetrated the portion of the sealed region of the borehole wall and before the perforator has been removed from the penetrated portion of the sealed region of the borehole wall. The method may further comprise: removing the perforator from the penetrated portion of the sealed region of the borehole wall after injecting the fluid from the fluid chamber into the formation through the perforator; and repeating the sealing, projecting, injecting, and removing steps at each of plurality of orientations of the downhole tool. The method may further comprise: measuring a closure stress at each of the plurality of orientations of the downhole tool; and determining at least one of a minimum horizontal stress value, a maximum horizontal stress value, and a horizontal stress orientation relative to a reference, based on the resulting plurality of closure stress measurements. The method may further comprise determining a permeability of a portion of the formation based on at least one of the injected fluid and a result of the fluid injection. The method may further comprise determining mobility of the fluid injected into the formation. The method may further comprise performing a leak-off test on the subterranean formation. Conveying the downhole tool within the borehole may comprise conveying the downhole tool via at least one of a wireline and a drill string. 
     It will be understood from the foregoing description that various modifications and changes may be made in the various and alternative embodiments of the present disclosure without departing from its true spirit. 
     The Abstract at the end of this disclosure is provided to comply with 37 C.F.R. §1.72(b) to allow the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.