Patent Abstract:
Methods and related systems are described for measuring acoustic signals in a borehole during a fracturing operation. The system includes a downhole toolstring designed and adapted for deployment in a borehole formed within a subterranean rock formation. A downhole rock fracturing tool opens and propagates a fracture in the subterranean rock formation. Dipole and/or quadrupole acoustic sources transmit acoustic energy into the subterranean rock formation. A receiver array measures acoustic energy traveling through the subterranean rock formation before, during and after the fracture induction. Geophones mounted on extendable arms can be used to measure shear wave acoustic energy travelling in the rock formation. The toolstring can be constructed such that the sources and receivers straddle the fracture zone during the fracturing. Alternatively, the sources or the receivers can co-located axially with the fracture zone, or the toolstring can be repositioned following fracturing such that the fracture zone is between the acoustic sources and receivers.

Full Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    This patent application is a continuation-in-part of International Patent Application PCT/US08/87970, filed Dec. 21, 2007, which is incorporated by reference herein. 
     
    
     BACKGROUND OF THE INVENTION 
       [0002]    1. Field of the Invention 
         [0003]    This patent specification relates to downhole acoustic measurements in connection with downhole fluid sampling and testing. More particularly, this patent specification relates to systems and methods for making and analyzing acoustic measurements in combination with a downhole hydraulic fracturing tool system. 
         [0004]    2. Background of the Invention 
         [0005]    In the oilfield service industry, characterizing commercially viable reservoirs of hydrocarbons is a main objective of well logging services. Downhole sampling and testing tools such as the Modular Dynamic Formation Tester (MDT) from Schlumberger are used during the well logging phase to gain a more direct assessment of the production characteristics of the accumulation. In one common configuration, the MDT is arranged with dual packers set against the borehole wall, thereby creating an isolated fluid interval in the annulus bounded by the tool outer surface, the borehole wall, and the two inflatable packers. Additional modules within the MDT enable controlled changes in pressure and flow in the interval. 
         [0006]    In some types of testing operations, rapid changes in pressure sometimes occur. For example, in a microhydraulic fracturing test, the interval is pressurized by pumping fluid into the annulus until a tensile fracture begins. The initiation is recorded by a breakdown on a pressure-vs-time record sampled at about one sample per second. It is desirable to evaluate these rapid changes in greater detail. Further detail of acoustic measurements during microhydraulic fracturing testing and in connection with other downhole sampling and testing tool systems is disclosed in International Patent Application PCT/US08/87970, filed Dec. 21, 2007 which is incorporated by reference herein. It is desirable to farther improve the evaluations of the formation when performing microhydraulic fracturing testing. 
       SUMMARY OF THE INVENTION 
       [0007]    According to embodiments, system for measuring acoustic signals in a borehole during a fracturing operation is provided. The system includes a downhole toolstring designed and adapted for deployment in a borehole formed within a subterranean rock formation. A downhole rock fracturing tool forms part of the toolstring, and is designed and adapted to open and propagate a fracture in the subterranean rock formation. One or more acoustic sources are mounted to the toolstring, and are designed and adapted to transmit acoustic energy into the subterranean rock formation. One or more acoustic sensors are also mounted to the toolstring, and are designed and adapted to measure part of the acoustic energy traveling through the subterranean rock formation. 
         [0008]    According to embodiments, a method for measuring acoustic signals in a borehole during a fracturing operation is provided. The method includes positioning a downhole toolstring in a borehole formed within a subterranean rock formation; inducing fracturing in rock formation using a rock fracturing tool forming part of the toolstring; transmitting acoustic energy into the rock formation using one or more acoustic sources mounted to the toolstring; and measuring acoustic energy traveling through the rock formation using one or more acoustic sensors mounted to the toolstring. 
         [0009]    Further features and advantages of the invention will become more readily apparent from the following detailed description when taken in conjunction with the accompanying drawings. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0010]    The present invention is further described in the detailed description which follows, in reference to the noted plurality of drawings by way of non-limiting examples of exemplary embodiments of the present invention, in which like reference numerals represent similar parts throughout the several views of the drawings, and wherein: 
           [0011]      FIG. 1  shows a downhole system for making acoustic measurements with a downhole microhydraulic fracturing and fluid sampling tool, according to embodiments; 
           [0012]      FIG. 2  shows a downhole system for making acoustic measurements with a downhole microhydraulic fracturing and fluid sampling tool, according to embodiments; 
           [0013]      FIG. 3  shows a downhole system for making acoustic measurements with a downhole microhydraulic fracturing and fluid sampling tool, according to other embodiments; 
           [0014]      FIG. 4  shows a downhole system for making acoustic measurements with a downhole microhydraulic fracturing and fluid sampling tool, according to further embodiments; 
           [0015]      FIG. 5  shows a downhole system for making acoustic measurements with a downhole microhydraulic fracturing and fluid sampling tool, according to yet further embodiments; 
           [0016]      FIG. 6  is a flow chart showing steps in running an system as shown in  FIG. 5 , according to embodiments; 
           [0017]      FIGS. 7   a  and  7   b  show repositioning of a downhole system such as shown in  FIG. 5 , according to some embodiments; 
           [0018]      FIG. 8  shows further detail of a receiver module for making acoustic measurements with a downhole microhydraulic fracturing and fluid sampling tool, according to some embodiments; 
           [0019]      FIG. 9  shows the receiver module of  FIG. 8  mounted within a microhydraulic fracturing and fluid sampling tool, according to embodiments; and 
           [0020]      FIG. 10  shows further detail of an acoustic sensor mounted on a receiver module, according to some embodiments. 
       
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
       [0021]    The particulars shown herein are by way of example and for purposes of illustrative discussion of the embodiments of the present invention only and are presented in the cause of providing what is believed to be the most useful and readily understood description of the principles and conceptual aspects of the present invention. In this regard, no attempt is made to show structural details of the present invention in more detail than is necessary for the fundamental understanding of the present invention, the description taken with the drawings making apparent to those skilled in the art how the several forms of the present invention may be embodied in practice. Further, like reference numbers and designations in the various drawings indicated like elements. 
         [0022]    It has been found that by making and properly recording acoustic and/or micro-acoustic frequency measurements, in-situ evaluations of rock mechanical properties and environmental stress can be performed. For example, by monitoring changes in the rock&#39;s acoustic response before, during and/or after the creation of a mini-hydraulic fracture, such evaluations can be made. According to embodiments, evaluating minimum stress direction stress and estimation of hydraulic fracture compliance by detecting changes in acoustic propagation can be accomplished using a combination of the mini-hydraulic fracturing tool such as Schlumberger&#39;s MDT tool, and an acoustic tool having cross dipole sources and receivers, such as Schlumberger&#39;s Sonic Scanner tool. In addition, the combination of known stress test procedures and an acoustic monitoring device can be used to get a more accurate closure pressure time to estimate the magnitude of the minimum stress. 
         [0023]    When a fracture in a rock formation is induced by hydraulic fracturing (or drilling) process, the fracture azimuth is related to stress directions. Acoustic tool such as Schlumberger&#39;s Sonic Scanner tool can be used to detect fracture azimuth by looking for changes in cross-dipole shear anisotropy due to the induced or natural fracture. See, e.g. Prioul, R., C., Signer, A., Boyd, A., Donald, R., Koepsell, T., Bratton, D., Heliot, X., Zhan, 2007, “Discrimination of fracture and stress effects using image and sonic logs hydraulic fracturing design,” The Leading Edge, September 2007; and Prioul, R., A., Donald, R., Koepsell, Z. El Marzouki, T., Bratton, 2007, “Forward modeling of fracture-induced sonic anisotropy using a combination of borehole image and sonic logs,” Geophysics, Vol. 72, pp. E135-E147, both of which are incorporated by reference herein. Furthermore, acoustic data from a tool such as Schlumberger&#39;s Sonic Scanner can be used to estimate the fracture compliance property required to assess area of fracture and farther geomechanical analysis. See, e.g. U.S. Pat. No. 7,457,194; and Prioul, R., J. Jocker, P. Montaggioni, L. Escare, “Fracture compliance estimation using a combination of image and sonic logs,” SEG 2008, both of which are incorporated by reference herein. 
         [0024]    According to embodiments, the ability is provided to detect mechanical and acoustic changes depending on the stress state and the fracture adding excess compliance to the rock system at the time the log is run (after the pressure has returned to equilibrium). According to some embodiments, the effect is enhanced, and hence, the measurement made more robust, by making the acoustic measurements while the fracture is still held open by the annular pressure in the MDT interval. According to other embodiments, the acoustic measurements are made while the fracture is held open by a proppant material that is significantly compliant in shear. Moreover, by measuring the acoustic response before and during fracture opening, the data can be analyzed to determine complex fracture trajectories and estimate hydraulic fracture compliances. For instance, early in the fracture growth the hoop stress dominates and the fracture growth is responsive to hoop stress geometries. The corresponding interpretation determines the direction and geometry of the fracture subject to this near wellbore condition. As the fracture continues to grow, differential analysis of the acoustic signature coupled with previous determinations of the characteristics of the (growing) fracture enables the evolution of the fracture to be determined. 
         [0025]    Various embodiments are described herein, with many having the following components in common: 
         [0026]    1. A cross-dipole transmitter (e.g. a vibration-generating device capable of creating vibration with mirror-antisymmetry with respect to either of two mutually orthogonal axial planes) such as the transmitter section of Schlumberger&#39;s Sonic Scanner tool; 
         [0027]    2. A fracturing device (FD), such as the dual-packer MDT tool from Schlumberger, capable of generating, in an axisymmetric way, pressure sufficient to initiate and grow a fracture in an isolated interval of borehole; and 
         [0028]    3. A cross-dipole receiver (e.g. a vibration-sensing device capable of detecting vibration with mirror-antisymmetry with respect to either of two mutually orthogonal axial planes) such as the receiver section of Schlumberger&#39;s Sonic Scanner tool. 
         [0029]      FIG. 1  shows a downhole system for making acoustic measurements with a downhole microhydraulic fracturing and fluid sampling tool, according to embodiments. Wireline logging system  100  is shown including multiple tools for taking geophysical measurements. Wireline  103  is a power and data transmission cable that connects the tools to a data acquisition and processing system  105  on the surface. The tools connected to the wireline  103  are lowered into a well borehole  107  to obtain measurements of geophysical properties for the surrounding subterranean rock formation  110 . The wireline  103  supports tools by supplying power to the tool string  101 . Furthermore, the wireline  103  provides a communication medium to send signals to the tools and to receive data from the tools. 
         [0030]    The tools, sometimes referred to as modules are typically connected via a tool bus  193  to telemetry unit  191  which is turn is connects to the wireline  103  for receiving and transmitting data and control signals between the tools and the surface data acquisition and processing system  105 . Commonly, the tools are lowered to a particular depth of interest in the borehole and are then retrieved by reeling-in by the data acquisition and processing system  105 . For sampling and testing operations, such as Schlumberger&#39;s MDT tool, the tool is positioned at location and data is collected while the tool is stationary and sent via wireline  103  to data acquisition and processing system  105  at the surface, usually contained inside a logging truck or logging unit (not shown). 
         [0031]    Electronic power module  120  converts AC power from the surface to provide DC power for all modules in the tool string  101 . Pump out module  130  is used to pump unwanted fluid, for example mud filtrate, from the formation to the borehole, so that representative samples can be taken from formation  110 . Pump out module  130  can also be used to pump fluid from the borehole into the flowline for inflating packers in module containing inflatable packers. Pump out module  130  can also be configured to transfer fluid from one part element of the tool string to another. Hydraulic module  132  contains an electric motor and hydraulic pump to provide hydraulic power as may be needed by certain modules. The tool string  101  can also include other sensor such as a strain gauge and a high resolution CQG gauge. Examples of a fluid sampling system using probes and packers are depicted in U.S. Pat. Nos. 4,936,139 and 4,860,581 where are incorporated by reference herein. 
         [0032]    Dual-packer module  150  includes an upper inflatable packer element  152 , lower packer element  154 , valve body  160  and electronics  162 . Inflatable packer elements  152  and  154  seal against the borehole wall  107  to isolate an interval of the borehole. Pumpout Module  130  inflates the packers with wellbore fluid. The length of the test interval (i.e., the distance between the packers) about 3.2 ft (0.98 m) and can be extended by inserting spacers between the packer elements. The area of the isolated interval of the borehole is about many orders of magnitude larger than the area of the borehole wall isolated by a probe. Dual-packer module  150  can be used to perform micro-hydraulic fracturing that can be pressure tested to determine the minimum in situ stress magnitude. A fracture, such as fracture  136 , is created by pumping wellbore fluid into the interval between the inflatable packer elements. Below dual-packer module  150  are one or more sample chamber units  170  for holding fluid samples collected downhole. 
         [0033]    According to embodiments, tool string  101  is provided with one or more acoustic transmitters and receivers for making acoustic measurements in connection with downhole fluid sampling and or testing. Transmitter module  128  can be a transmitter section of a wireline deployable sonic tool such as from the Sonic Scanner Tool from Schlumberger. Transmitter module  128  includes one or more monopole acoustic transmitters  122  that can produce strong pressure pulses or “clicks” generating clear P- and S-waves, from low frequency Stoneley mode to high frequency energy useful for some types of evaluations. Transmitter module  128  also includes two dipole transmitters  124   a  and  124   b,  which essentially are shaking devices, each consisting of an electromagnetic motor mounted in a cylinder suspended in the tool housing. The dipole sources generate a high-pressure dipole signal without inducing significant vibration in the tool housing. The dipole sources  124   a  and  124   b  are oriented orthogonally with respect to each other, such that one vibrates in line with the tool reference axis and the other at 90 degrees to the axis. The dipole sources generate strong flexural modes that propagate up and down the borehole and also into the formation to different depths that depend on their frequencies. According to embodiments, the dipole sources  124   a  and  124   b  are designed generate frequencies in a sweep from about 300 Hz to 8 kHz. 
         [0034]    According to some embodiments, the transducer elements of sources  124   a  and  124   b  are arcuate shaped and are designed an arranged such that they can be excited separately in a selected pattern to effectively excite other acoustic modes, such as quadrupole and higher-order modes. According to some embodiments, for example, each source  124   a  and  124   b  includes four-quadrant arcuate shaped members which are operated to generate quadrupole mode acoustic energy into the wellbore and rock formation. For further description of suitable transducer elements including arcuate shaped transducers for generating monopole, dipole, quadrupole and high-order modes, see e.g. U.S. Pat. No. 7,460,435, U.S. Pat. No. 7,364,007, and U.S. Patent Application Publication No. 2006/0254767, each of which are incorporated by reference herein. 
         [0035]    The receiver module  126  is a multi-pole receiver unit such as the receiver section of the Sonic Scanner Tool from Schlumberger. Receiver module  126  includes a number, for example  13 , of axial receiver stations  134  in a 6 foot (1.8 meter) receiver array. Each receiver station includes eight azimuthally distributed acoustic receivers, placed every 45 degrees for a total of  104  sensors on module  126 . The receiver module is preferably constructed using a central mandrel having a mass-spring structure. For further details of a suitable acoustic transmitter and receiver modules having mass-spring structure and a central mandrel, see e.g. U.S. Pat. No. 7,336,562, and Franco et. al. “Sonic Investigations In and Around the Borehole,” Oilfield Review, Spring 2006, pp. 16-45, each of which are incorporated herein by reference. 
         [0036]    According to some embodiments, a geopositioning and inclinometry tool  180  is also included in toolstring  101 . Tool  180  includes both a three-axis inclinometer and a three-axis magnetometer to make measurement for determining tool orientation in terms of three parameters: tool deviation, tool azimuth an relative bearing. According to some embodiments, a tool such as Schlumberger&#39;s General Purpose Inclinometry Tool (GPIT) is used for tool  180 . The measurements from tool  180  can be used for orientation of the acoustic sensors. Although not shown, it is understood that a geopositioning and inclinometry tool such as described herein can be included in the embodiments described with respect to  FIGS. 2-5  below. 
         [0037]    Note that unlike many commercially used acoustic tools such as Schlumberger&#39;s Sonic Scanner Tool, the transmitter module  128  does not have to be synchronized with the receiver module  126 . Additionally, as long as the orientation of the transceiver module  128  is not changed during the measurement procedure, the tool orientation need to be controlled or known. Preferably, the orientation of the receiver module  126  is known, and the receiver module  126  is capable of listening continuously or repeatedly with a substantial duty cycle. Also, according to some embodiments, the source time signature is controlled and known with enough precision to allow the received signal to be stacked for noise reduction and processed to determine relative orientation of the source and receiver dipoles. It has been found to be sufficient, for example, to have alternating pulses in the two dipole orientations repeated continuously with a precisely known delay between successive pulses. According to alternative embodiments, m-sequences, sweeps, or chirps are used. 
         [0038]    According to some embodiments, source dipoles can be denoted SA and SB. Receiver dipoles can be denoted Ra, Rb, and are not assumed to be parallel with SA, SB. The source firing schedule should alternate long (for example,  10  second) repetitions of SA and SB, followed by interleaved repetitions with a precisely controlled delay. Since the source firing schedule is known, the long states (LSA, LSB) can be known and separated timewise. Receiver states Ra and Rb are separate channels in the recording. Thus the total recorded signal during the long states can be partitioned into four distinct components LSARa, LSARb, LSBRa, LSBRb. Signal energy (sum of squared signal amplitude) from these components are then analyzed using known methods (for example, the Alford Rotation method) to determine rotation unit vectors to be used to minimize cross-energy. 
         [0039]    If the initial state of the rock is Transversely Isotropic with its symmetry axis aligned to the borehole, this minimization will only depend on the relative angle between source and receiver rotations, which will be a measure of the orientation of the source. In an orthorhombic initial state (as can be expected with unequal horizontal stresses), the minimum will only be achieved when the receivers are rotated to align to the orthorhombic stress symmetry planes and the sources are rotated to align with the receivers. 
         [0040]    After rotation, the received signal in the interleaved data will show delays between repetitions that are slightly large when alternating from slow to fast directions and slightly small when alternating from fast to slow and hence can be used to determine which are the fast and slow shear directions. Without a time synchronization between source and receiver, absolute traveltime will not be directly measureable. However, since velocity across the receiver array can be measured, equations requiring a reference traveltime can use a reference traveltime obtained by dividing the known Transmitter/Receiver spacing by this measured velocity at the receiver. Note that the determination of relative source orientation need only be performed once. 
         [0041]    As the fracture is created and grown, the azimuthal anisotropy becomes larger both in the energy difference and time difference between fast and slow directions. Time-lapse processing, in which baseline waveforms are subtracted to enhance the ability to see slight changes or drifts, are useful here. Time reference for this subtraction may be obtained either by aligning on some detected feature in the waveforms, or by maximizing cross-correlation, or by relying upon the known, precise repetition rate of the source. 
         [0042]      FIG. 2  shows a downhole system for making acoustic measurements with a downhole microhydraulic fracturing and fluid sampling, according to embodiments. The system of  FIG. 2  is very similar to that of  FIG. 1  with like reference numbers used for the same modules. However in the embodiment of  FIG. 2  the positions of the transmitter module  128  and the receiver module  126  on toolstring  101  are switched such that the transmitter module  128  is located above the dual packer module  150  and the receiver module  126  is located below dual packer module  150 . 
         [0043]      FIG. 3  shows a downhole system for making acoustic measurements with a downhole microhydraulic fracturing and fluid sampling tool, according to other embodiments. Similar to the systems shown in  FIGS. 1-2 , wireline logging system  300  includes multiple tools for taking geophysical measurements. Wireline  303  is a power and data transmission cable that connects the tools to a data acquisition and processing system  305  on the surface. The tools connected to the wireline  303  are lowered into a well borehole  307  to obtain measurements of geophysical properties for the surrounding subterranean rock formation  310 . The wireline  303  supports tools by supplying power to the tool string  301 . Furthermore, the wireline  303  provides a communication medium to send signals to the tools and to receive data from the tools. 
         [0044]    The tools are connected via a tool bus  393  to telemetry unit  391  which is turn is connects to the wireline  303  for receiving and transmitting data and control signals between the tools and the surface data acquisition and processing system  305 . The tool is positioned at a location and data is collected while the tool is stationary and sent via wireline  303  to data acquisition and processing system  305  at the surface, usually contained inside a logging truck or logging unit (not shown). Similar to the system shown in  FIG. 1 , electronic power module  320 , pump out module  330 , and hydraulic module  332  are provided. 
         [0045]    Tool string  301  also includes a receiver module  326 , which is similar to module  126  shown and described with respect to  FIG. 1 . Receiver module  326  includes a number, for example 13, of axial receiver stations  334  in a 6 foot (1.8 meter) receiver array, and each receiver station includes eight azimuthally distributed acoustic receivers, placed every 45 degrees. 
         [0046]    Dual-packer module  350  includes an upper inflatable packer element  352 , lower packer element  354 , valve body  360  and electronics  362 . Inflatable packer elements  352  and  354  seal against the borehole wall  307  to isolate an interval of the borehole. Pumpout Module  330  inflates the packers with wellbore fluid. Dual-packer module  350  can be used to perform micro-hydraulic fracturing that can be pressure tested to determine the minimum in situ stress magnitude. A fracture, such as fracture  336  is created by pumping wellbore fluid into the interval between the inflatable packer elements. The packer module  350  includes an autonomous acoustic source  328 . Source  328  is similar to transmitter module  128  shown and described with respect to  FIG. 1 , and includes one or more monopole acoustic transmitters  322  as well as two multi-pole (e.g. dipole or quadrupole) transmitters  324   a  and  324   b.  According to embodiments, source  328  is autonomous and is programmed to fire on a precise regular schedule while using measuring the acoustic response using receiver module  326 . These acoustic measurements are carried out preferably before, during and after the formation of fracture  336 . Below dual-packer module  350  are one or more sample chamber units  370  for holding fluid samples collected downhole. 
         [0047]      FIG. 4  shows a downhole system for making acoustic measurements with downhole microhydraulic fracturing and fluid sampling, according to further embodiments. The system of  FIG. 4  is very similar to that of  FIG. 3  with like reference numbers used for the same modules. However in the embodiment of  FIG. 4  the positions of the source  328  and the receiver module  326  on toolstring  301  are switched such that source  328  is located above the dual packer module  350  and the receiver module  326  is located between the packers of dual packer module  350 . 
         [0048]      FIG. 5  shows a downhole system for making acoustic measurements with downhole microhydraulic fracturing and fluid sampling, according to yet further embodiments. Similar to the systems shown in  FIGS. 1-4 , wireline logging system  500  includes multiple tools for taking geophysical measurements. Wireline  503  connects the tools to a data acquisition and processing system  505  on the surface. The tools connected to the wireline  503  are lowered into a well borehole  507  to obtain measurements of geophysical properties for the surrounding subterranean rock formation  510 . The wireline  503  supports tools by supplying power to the tool string  501 , and provides a communication medium to send signals to the tools and to receive data from the tools. The tools are connected via a tool bus  593  to telemetry unit  591  which is turn is connects to the wireline  503 . The tool is positioned at a location and data is collected while the tool is stationary and sent via wireline  503  to data acquisition and processing system  505  at the surface. Similar to the systems shown in  FIGS. 1-4 , electronic power module  520 , pump out module  530 , and hydraulic module  532  are provided. 
         [0049]    Dual-packer module  550  includes an upper inflatable packer element  552 , lower packer element  554 , valve body  560  and electronics  562 . Inflatable packer elements  552  and  554  seal against the borehole wall  507  to isolate an interval of the borehole. Pumpout Module  530  inflates the packers with wellbore fluid. Dual-packer module  550  can be used to perform micro-hydraulic fracturing that can be pressure tested to determine the minimum in situ stress magnitude. A fracture, such as fracture  536  is created by pumping wellbore fluid into the interval between the inflatable packer elements. Below dual-packer module  550  are one or more sample chamber units  570  which can be used for holding fluid samples collected downhole. According to some embodiments, sample chamber units  570  can also be used to hold proppant material which is pumped into the packed-off interval and into the fracture  536 , as will be described in further detail herein. 
         [0050]    Tool string  501  also includes a receiver module  526 , which is similar to module  126  shown and described with respect to  FIG. 1 . Receiver module  526  includes a number, for example  13 , of axial receiver stations  534  in a 6 foot (1.8 meter) receiver array, and each receiver station includes eight azimuthally distributed acoustic receivers, placed every 45 degrees. Tool string  501  also includes a transmitter module  528  is similar to transmitter module  128  shown and described with respect to  FIG. 1 . Transmitter module  528  includes one or more monopole acoustic transmitters  522  as well as two multi-pole (e.g. dipole or quadrupole) transmitters  524   a  and  524   b.    
         [0051]    According to some embodiments, stored in one or more of the sample chamber units  570  is a proppant material that is significantly compliant in shear and which can decay with time over a relatively short period. 
         [0052]    Examples of a suitable proppant material include: (1) calcined calcium carbonate, which can be dissolved using mild acid; (2) polylactic, polyglycolic acid beads or the like in water, which dissolve at various rates as temperature increases; (3) crystalline sodium chloride in a sodium chloride solution, which can be dissolved by “flowing back” or circulating pure water; and (4) magnesium oxide which can be dissolved by circulating an ammonium chloride solution. According to other embodiments, the fracture  536  is propagated with a resinous material such as polyurethane, epoxy or other curing polymeric material that forms a solid mass after a predetermined time. 
         [0053]      FIG. 6  is a flow chart showing steps in running an system as shown in  FIG. 5 , according to embodiments. In step  610 , a toolstring having both dual packer downhole fracturing capability and cross dipole acoustic sources and receivers, such as shown in  FIG. 5 , deployed downhole. In step  612 , the dual packers are set. In step  614 , the rock fracturing is initiated. After opening and growing the fracture with the fracturing tool module, stress cycles are performed to determine minimum stress value of the formation (i.e. until the fracture exits the hoop stress region and fully enters the far field stress region). In step  616 , proppant material is injected into the fracture to prevent or delay the fracture closure. 
         [0054]    In step  618 , the tool combination is shifted so that the fracture is between the transmitter and receiver sections of the sonic tool. In step  620 , the sonic tool transmitters generate dipole acoustic energy and the sonic tool receivers measure the response. In step  622 , an analysis is performed for determination of fracture azimuth and excess compliance. The analysis can be as described, for example, in: Prioul, R., A., Donald, R., Koepsell, Z. El Marzouki, T., Bratton, 2007, Forward modeling of fracture-induced sonic anisotropy using a combination of borehole image and sonic logs, Geophysics, Vol. 72, pp. E135-E147; and Prioul, R., J. Jocker, P. Montaggioni, L. Escare (2008), Fracture compliance estimation using a combination of image and sonic logs, SEG 2008, which is incorporated by reference herein. 
         [0055]    According to some embodiments, time-lapse processing, in which baseline waveforms are subtracted to enhance the ability to see slight changes or drifts, and to make evaluations of rock properties at locations further from the borehole than would be possible without such subtraction techniques. Time reference for this subtraction may be obtained either by aligning on some detected feature in the waveforms, or by maximizing cross-correlation, or by relying upon the known, precise repetition rate of the source. For further detail in analyzing the sonic and ultrasonic waveforms, see, U.S. Pat. No. 5,859,811, which is incorporated by reference herein 
         [0056]      FIGS. 7   a  and  7   b  show repositioning of a downhole system such as shown in  FIG. 5 , according to some embodiments. In  FIG. 7   a,  toolstring  501  is positioned such that dual packer module  550  is able to isolate an annular region and create fracture  536 . As described herein, a proppant material is injected into fracture  536  such that the fracture remains open long enough for the toolstring to be repositioned and for acoustic measurements to be made. In  FIG. 7   b,  The toolstring  501  is shown repositioned such that the induced fracture  536  is between acoustic transmitter module  528  and acoustic receiver module  526 . 
         [0057]      FIG. 8  shows further detail of a receiver module for making acoustic measurements with a downhole microhydraulic fracturing and fluid sampling tool, according to some embodiments. Receiver module  826  includes sensor section  830 . Sensor section  830  includes a number of sensors, including acoustic sensors and 3-axis geophones. A number of acoustic sensors, for example, sensors  834   a  and  834   b  are mounted on the surface of sensor section  830 . In this example, four azimuthally spaced acoustic sensors are mounted in each station, and there are six stations for a total of 24 acoustic sensors on sensor section  830 . Six geophones are also included in sensor section  830 , four geophones are shown in the view of  FIG. 8 , namely geophones  840   a,    840   b,    840   c  and  840   d.  Each geophone is mounted on an extendable arm so as to be in contact with the borehole wall during measurement. The extendable arms are similar to those used on centralizer arms commonly used in downhole tools. Geophones  840   a,    840   b,    840   c  and  840   d  are shown mounted on arms  842   a,    842   b,    842   c  and  842   d,  respectively. Each of the geophones are 3-axis and by contacting the borehole wall, they allow for recording of both compressional and shear components of the incident acoustic waves. According to some embodiments, the geophones are also capable of receiving micro-acoustic emissions at ultrasonic frequency. 
         [0058]    Flowline  810  allows for fluid communication between other modules of the microhydraulic fracturing and fluid sampling tool which may be located both above and below receiver module  826  as described elsewhere herein. Valves  812   a,    812   b,    812   c  and  812   d  may be manual or automatically closed depending on the hydraulic layout of the tool system. Control signals to and data from both the acoustic sensors and geophones on sensor section  830  are sent and received from module electronics  816 . Module electronics  816 , in turn, sends and receives data with the rest of the tool system and with the surface via tool bus  893 . 
         [0059]      FIG. 9  shows the receiver module of  FIG. 8  mounted within a microhydraulic fracturing and fluid sampling tool, according to embodiments. In the example shown, receiver module  826  is mounted immediately above dual packer module  950  and below other modules such as a pump out module and/or a hydraulic module (not shown) as described in  FIG. 1 . According to some embodiments, a bumper guard  910  is provided to protect the sensors on sensor section  830 . The bumper guard  910  is useful, for example, in cases where extendable arms are not used in connection with geophones. Note although the receiver module  830  is shown immediately above the dual packer module  950  in  FIG. 8 , the receiver module as described in  FIGS. 8 and 9  can be used in other positions and incorporated into other modules as shown and described with respect to  FIGS. 1-5  herein. 
         [0060]      FIG. 10  shows further detail of an acoustic sensor mounted on a receiver module, according to some embodiments. A sonic detector  1012  is shown mounted on tool housing wall  1020 . A detector housing  1014  surrounds the detector  1012 , which receives control signals and sends data via wire  1024  passing through a small hole in housing  1020 . Additionally, guards  1010   a  and  1010   b  are provided to protect the detector from mechanical damage in the downhole environment. 
         [0061]    Whereas many alterations and modifications of the present invention will no doubt become apparent to a person of ordinary skill in the art after having read the foregoing description, it is to be understood that the particular embodiments shown and described by way of illustration are in no way intended to be considered limiting. Further, the invention has been described with reference to particular preferred embodiments, but variations within the spirit and scope of the invention will occur to those skilled in the art. It is noted that the foregoing examples have been provided merely for the purpose of explanation and are in no way to be construed as limiting of the present invention. While the present invention has been described with reference to exemplary embodiments, it is understood that the words, which have been used herein, are words of description and illustration, rather than words of limitation. Changes may be made, within the purview of the appended claims, as presently stated and as amended, without departing from the scope and spirit of the present invention in its aspects. Although the present invention has been described herein with reference to particular means, materials and embodiments, the present invention is not intended to be limited to the particulars disclosed herein; rather, the present invention extends to all functionally equivalent structures, methods and uses, such as are within the scope of the appended claims.

Technology Classification (CPC): 4