Abstract:
A method of monitoring acoustic activity in a formation from a wellbore includes positioning a flow manipulation device into the wellbore, the flow manipulation device defining a flow path through which fluid may flow. Fluid is then pumped into the wellbore and through the manipulation device. A sensor disposed near the manipulation device is then coupled to the formation, the formation is fractured with fluid, and acoustic events in the formation are detected with the sensor.

Description:
CROSS-REFERENCE TO RELATED APPLICATION 
     This application claims the benefit of co-pending U.S. Provisional Application No. 61/039,776, filed on Mar. 26, 2008, the content of which is incorporated herein by reference for all purposes. 
    
    
     FIELD OF THE DISCLOSURE 
     The present disclosure generally relates to methods and apparatus for exploring subsurface formations. More particularly, the present disclosure relates to methods and apparatus for sensing acoustic activity in subsurface formations. 
     BACKGROUND OF THE DISCLOSURE 
     Various types of acoustic sensing are used during hydrocarbon production. Generally speaking, acoustic sensing may be active or passive. Active acoustic sensing applications include vertical seismic profiling and hydrofracture monitoring, or any other application that includes source activation. In hydrofracture monitoring, for example, a fluid may be injected into the formation to stimulate microseismic activity. Passive applications do not use ancillary means to stimulate the well but instead simply monitor acoustic activity created during production, or monitoring. In each sensing application, the acoustic sensors are used to obtain information to help operators better understand the characteristics of the fracture, such as propagation direction, geometry, dip, and other parameters. In active monitoring applications, the information permits adjustment, in real time, of the injection process parameters in case of a mismatch between the planned and actual fracture. The “real-time” expression refers here to enabling a reaction in a time which is fast enough to have an impact on the economics of the fracturing job (for instance stopping the injection in case the fracture is in danger of extending into a water zone). 
     Many current microseismic fracture monitoring systems employ a wireline seismic array tool deployed in a monitoring well. A monitoring well, however, is not always available or suitable for microseismic monitoring (e.g., if located too far from the injection well). In addition, there is a high cost associated with running a seismic wireline tool in a monitoring well, mainly coming from the preparation of the monitoring well. 
     Other fracture monitoring systems have been proposed in which the sensors are deployed in the injection well, thereby eliminating the need for a monitoring well. These systems, however, are typically limited to use in applications where tubing is used to convey the fracture fluid. 
     SUMMARY OF THE DISCLOSURE 
     According to one embodiment disclosed herein, a method of monitoring acoustic activity in a formation having a wellbore is provided in which a flow manipulation device is positioned into the wellbore, the flow manipulation device defog a chamber and a flow path through which fluid may flow. A sensor unit is positioned in the flow manipulation device chamber such that the sensor unit is separated from the flow path by the flow manipulation device. Finally, acoustic activity is detected in the formation with the sensor unit. 
     In another embodiment, an apparatus is provided for obtaining acoustic data from a formation having a wellbore formed therein. The apparatus includes a housing sized for insertion into the wellbore, the housing including an exterior wall, an interior wall defining a flow path through which fluid may flow, and a chamber disposed between the exterior and interior walls. A sensor unit is disposed in the housing chamber and responsive to acoustic energy emanating from the formation. 
     In a further embodiment, a method of monitoring microseismic events in a formation from a wellbore is provided that includes positioning a flow manipulation device into the wellbore, the flow manipulation device defining a flow path through which fluid may flow. Fluid is then pumped into the wellbore and through the manipulation device. A sensor disposed near the manipulation device is then coupled to the formation, the formation is fractured with fluid, and acoustic activity in the formation is detected with the sensor. 
     Other advantages and features will be apparent from the following detailed description when read in conjunction with the attached drawings. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a more complete understanding of the disclosed methods and apparatuses, reference should be made to the embodiments illustrated in greater detail in the accompanying drawings, wherein: 
         FIG. 1  is a schematic side elevation view, in partial cross-section, of a downhole monitoring tool positioned in a wellbore; 
         FIG. 2  is a perspective, cross-sectional view of the monitoring tool of  FIG. 1 ; 
         FIG. 3  is a plan, cross-sectional view of an acoustic monitoring tool disposed in a wellbore and having a coupling system; 
         FIG. 4  is side elevation view in cross-section of an acoustic monitoring tool having a packer in a retracted position; and 
         FIG. 5  is a side elevation view in cross-section of the acoustic monitoring tool of  FIG. 4 , with the packer in the expanded position. 
     
    
    
     It should be understood that the drawings are not necessarily to scale and that the disclosed embodiments are illustrated graphically, diagrammatically and in partial views. In certain instances, details which are not necessary for an understanding of the disclosed methods and apparatuses or which render other details difficult to perceive may have been omitted. It should be understood, of course, that this disclosure is not limited to the particular embodiments illustrated herein. 
     DETAILED DESCRIPTION 
     So that the above recited features and advantages of the present disclosure can be understood in detail, a more particular description of the disclosure may be had by reference to the embodiments thereof that are illustrated in the accompanied drawings. It is to be noted, however, that the drawings illustrate only typical embodiments of this disclosure and are therefore not to be considered limiting of its scope, for the disclosure may admit to other equally effective embodiments. 
     An acoustic monitoring system is disclosed which can be deployed in the treatment well, thereby eliminating the need for a monitoring well. The tool may be operated as either a memory tool or as a wireline tool, and is configured to facilitate easy removal from the wellbore. 
     When the tool is a memory tool, acoustic data may be recorded to a memory device (hard disk or flash), and the tool may powered by a battery. The tool may be deployed using a wireline in which case the tool is coupled to the formation as shown in  FIGS. 1 and 2  and as described in more detail below. Alternatively, the tool may be deployed during casing deployment for open hole non-cemented wells, in which case the tool is connected to a casing joint, possibly via a mandrel. In this case, the tool is either connected to the surface recording equipment using a control line deployed behind casing or, in the case of a memory tool, accessed by wireline. In another exemplary embodiment, the tool may be conveyed by coiled tubing and may be attached at a distal end thereof. Regardless of the manner of conveyance, as the tool is retrieved after/during the job, data is analyzed after the fracture of the formation. 
     When the tool is a wireline tool, the tool may be deployed just before injection of fracturing fluid. The wireline is used to provide power to the downhole electronics and motors, and to convey the digital data uphole. The communication link can either be copper or optical telemetry. Acoustic coupling of the sensors to the formation may be ensured by a motor actuated retractable system as shown in  FIG. 3 , although alternate methods or apparatus may be used. 
     Furthermore, while one aspect of the disclosure is monitoring microseismicity induced by hydraulic fracturing or reservoir activity, this disclosure also contemplates the field of VSP (Vertical Seismic profiling), where an active source (airgun, dynamite or vibroseis) is used to generate an acoustic signal. 
       FIG. 1  illustrates a hydraulic fracture monitoring system  10  employed in a wellbore  12 . The wellbore  12  traverses a formation  14  having a reservoir or area  16  designated for hydraulic fracture. The wellbore  12  may be lined, such as with mudcake or a casing  122 . 
     A hydraulic fracture system  18  is provided for injecting fracture fluid into the reservoir  16 . The hydraulic fracture system  18  may include a source of fracture fluid, a pump operably coupled to the fracture fluid source, and a fracture fluid controller  20  for controlling operation of the pump. The system  18  is operable to inject fluid into the wellbore  12 , thereby increasing fluid pressure in the reservoir  16  to stimulate microseismic activity. An exemplary point  22  exhibiting microseismic activity is shown in  FIG. 1  propagating seismic waves  24 , which may include compression wave (“P-wave”) and shear wave (“S-wave”) components. 
     A downhole monitoring tool  120  is disposed in the wellbore  12  for detecting microseismic activity in the formation. In the embodiment illustrated in  FIG. 1 , the tool  120  is configured as a wireline tool. Accordingly, the tool  120  is attached to a cable  26  deployed from a rig  28 . While  FIG. 1  shows the rig  28 , a wireline arrangement that does not have a rig may be used. 
     As best shown in  FIG. 2 , the illustrated tool  120  includes a flow manipulation device in the form of a housing  124 . The housing  124  is configured to redirect fluid flow as it travels along the borehole in the vicinity of the tool  120 . Accordingly, the housing  124  defines a flow path along which the hydraulic fracture fluid may flow. 
     In the exemplary embodiment, the flow path is surrounded by the housing  124 . As best shown in  FIG. 2 , the housing  124  has a generally annular shape formed by an exterior wall  126  and an interior wall  128 . The exterior and interior walls  126 ,  128  may be formed of a material having a sufficient hardness to minimize erosion during use, and may be constructed of the same wall. The material may further have acoustic properties which attenuate noise. Exemplary materials suitable for use include steel, stainless steel, titanium alloy, and inconel, however other materials having sufficient hardness and/or noise attenuation may also be used. The walls  126 ,  128  may be formed entirely of a single material or may have a base layer and an external coating or layer. The exterior wall  126  is cylindrical and may define a substantially uniform diameter. The interior wall  128 , however, may include a first transition section  128   a , an intermediate section  128   b , and a second transition section  128   c . The first transition section  128   a  may have an irregular, frustoconical shape with an outer end  130  having a larger diameter and an inner end  132  having a smaller diameter. The intermediate section  128   b  may have a cylindrical shape with a substantially uniform diameter approximately equal to the smaller diameter of the first transition section inner end  132 . The second transition section  128   c  may have a frustoconical shape similar to, but inverted from, the first transition section  128   a . Accordingly, the second transition section  128   c  may have an inner end  134  sized at the smaller diameter and an outer end  136  having the larger diameter. The flow path defined by the housing  124 , therefore, has a varying cross-sectional area that gradually decreases through the first transition section  128   a , is substantially uniform through the intermediate section  128   b , and gradually increases through the second transition section  128   c.    
     The flow path may further be configured to minimize the amount of noise generated by fluid flowing therethrough. Accordingly, the housing interior wall  128  may be shaped to promote laminar fluid flow along the path. 
     The housing  124  further provides an enclosure for protecting a sensor unit  142  from the injection fluid. As best shown in  FIG. 2 , the housing  124  defines a chamber  140  sized to receive the sensor unit  142 . The chamber  140  is formed in the annular space between the exterior wall  126  and the interior wall  128 , or may simply be within or on the tool  120 . The chamber  140  is widest at a central portion located between the intermediate section  128   b  of the interior wall and the exterior wall  126 . As shown in the illustrated embodiment, a centerline  144  of the intermediate section  128   b  may be offset from a centerline  146  of the casing  122  to maximize the width of the chamber central portion. 
     The sensor unit  142  is disposed in the housing chamber  140  and is configured to detect microseismic activity in the formation. The sensor unit  142  may include one or more sensors  143  ( FIG. 1 ) for detecting seismic, acoustic, or related energy. Exemplary sensors include hydrophones, geophones (including optical), MEMS, pressure/temperature sensors, or other types of sensors, or combinations thereof. 
     A data processing system  110  is operatively coupled to the sensor unit  142  by the cable  26  ( FIG. 1 ). The data processing system  110  is configured to receive, store, and/or process signals from the sensors  143 . Accordingly, the data processing system  110  may include control, communication, and processing circuitry, a power supply, a processor, a RAM, a recorder, and the like. In certain embodiments, the data processing system  110  may omit one or more of the foregoing components. For example, if an optical geophone is used, it may be coupled to the data processing system  110  using optical fiber, in which case electrical power is not needed to transmit the signals. The processor may be a suitably programmed general purpose computer system, a special purpose digital or analog computer, or other device. 
     Based on the acoustic signals generated by the sensors  143 , the data processing system  110  may run programs containing instructions that, when executed, perform various routines for processing the signals. These routines may be fully automated and capable of continuous operation in time for monitoring, detecting, and locating microseismic events. An operator may receive results from the process routines in real time, such as on a display monitor, and may adjust hydraulic fracture parameters such as pumping pressure, stimulation fluid, and proppant concentrations to optimize wellbore stimulation based on the displayed information. 
     In operation, an acoustic monitoring tool  120  may be inserted into a wellbore using one of the many known methods. A source may then be activated to generate acoustic and/or seismic energy that is received by the tool sensor unit  142 . In the illustrated embodiment, the energy source is microseismic activity in the formation induced by hydraulic fluid pressure in the reservoir. Alternatively, the energy source may be located at the surface, in the wellbore, or at an adjacent monitoring wellbore. During fracture fluid injection, the tool  120  directs the fluid flow away from the sensor unit  142 , thereby enabling the sensor unit  142  to be disposed in the same wellbore as the injection fluid. The annular shape of the housing  124  shown in  FIG. 2  prevents, or at least minimizes, flow restriction during the injection process to facilitate fracture fluid injection. The energy sensed by the sensor unit  142  is converted into a signal representing data, such as seismic data. The data is communicated to the data processing system  110 , in which one or more stored programs will process the data to derive useful information regarding the location, geometry, or other characteristics of the microfractures in the formation. 
     While the foregoing describes a single acoustic monitoring tool  120  in the wellbore  12 , multiple tools may be used. Furthermore, additional downhole tools other than microseismic monitoring tools may be deployed in the wellbore  12 . 
     An optional coupling system may be provided for reducing unwanted noise during acoustic sensing. The coupling system may be used to place the sensor unit nearer to or in direct contact with the casing, thereby to improve seismic/acoustic sensing. Additionally, the coupling system may better secure the tool in place, thereby to damp unwanted vibrations or other sources of undesirable noise. Without a coupling system, the tool may tend to move or vibrate during fluid flow, thereby generating noise. Various types of coupling systems may be used, either individually or in combination, to minimize or eliminate unwanted noise. 
       FIG. 3  illustrates an acoustic monitoring tool  150  including a piston-type coupling system  152 . The tool  150  is disposed in a casing  154 , and includes a housing  156  in which a sensing unit  158  is disposed. The coupling system  152  includes arms  160  coupled to the housing  156  and a contact pad  162  coupled to the arms  160 . The arms  160  are radially extendable between a retracted position, in which the contact pad  162  is positioned closer to the housing  156 , and an extended position, in which the contact pad  162  is farther from the housing  156  to engage the casing  154  (as shown in  FIG. 3 ). Acoustic coupling between the sensor unit  158  and the microseismic energy source is provided when the contact pad  162  engages the formation or casing wall, as the sensor is in direct contact with, as opposed to off-set from, the formation/casing wall. 
     Additionally or alternatively, the sensor unit and/or housing may be suspended or may include a dampening mechanism to absorb and/or remove unwanted noise. In particular, the sensor unit may be connected to the tool using a mechanical filter, such that the sensor unit is isolated from the housing. The tool also may be connected to the formation/casing using a similar spring dashpot system. Alternatively, the sensor unit may be coupled to the tool by a magnetic system. 
       FIGS. 4 and 5  illustrate a further embodiment of an acoustic monitoring tool  200 . The tool  200  may include a housing  202  similar to that of the embodiment shown in  FIGS. 1-3 , but it also includes a packer  210  which may be used to seal between the wellbore and the tool  200  to force fluid through the tool  200 . The housing  202  may include an inner wall  203  defining a flow path  205 . The housing  202  is disposed in a wellbore  204  formed in a formation. 
     The packer  210  may be similar to conventional packers that are well-known in the art, except as discussed below. Accordingly, the packer  210  may have an annular shape extending around a periphery of the housing  202 . In the illustrated embodiment, the packer  210  defines an annular chamber  211 . The packer  210  may also have a contact surface  212 . The packer  210  may be formed of a resilient material that permits movement between a retracted position and an extended position. In the retracted position as best shown in  FIG. 4 , the contact surface  212  is spaced from the surface of the wellbore  204 . In the extended position as best shown in  FIG. 5 , the contact surface  212  engages the surface of the wellbore  204 . The packer  210  may be moved between retracted and expanded positions using any known type of packer actuator, such as controlling pressurized fluid flow into the packer interior chamber  211 . A controller may be provided for controlling actuation of the packer  210 . 
     The tool  200  further includes a sensor unit  214  for detecting acoustic and/or seismic energy. The illustrated sensor unit  214  is disposed in the packer interior chamber  211  and includes a chassis  216  holding one or more sensors  218 . Accordingly, the packer  210  provides a protective enclosure for the sensor unit  214 . As noted above, the one or more sensors  218  may include sensors for detecting seismic, acoustic, or related energy. Exemplary sensors include hydrophones, geophones (including optical), MWMS, pressure/temperature sensors, or other types of sensors, or a combination thereof. 
     The tool  200  may further include means for communicating sensed data to a remote location, such as to the surface. In the illustrated embodiment, a telemetry line  220  is operatively coupled to the sensor unit  214 , however other communication means may be used. Additionally or alternatively, the tool  200  may include storage media for storing the sensor data. 
     In operation, the packer  210  may be actuated to acoustically couple the sensor unit  214  to the formation. When the packer  210  is placed in the expanded position, such as by increasing fluid pressure in the chamber  211 , the contact surface  212  will engage the wellbore wall, as shown in  FIG. 5 , thereby placing the sensor unit  214  in close proximity to the formation. Multiple tools  200  may be spaced along the housing  202  to form a seismic array. 
     While the foregoing describes monitoring at a specific depth in the wellbore, it will be appreciated that the various tool embodiments disclosed herein may be quickly and easily repositioned to different wellbore depths to obtain acoustic information related to multiple target zones in the formation. 
     Moreover, inventive aspects lie in less than all features of a single disclosed embodiment. Thus, the claims following the Detailed Description are hereby expressly incorporated into this Detailed Description, with each claim standing on its own as a separate embodiment. The embodiments and aspects were chosen and described in order to best explain the principles of the invention and its practical application. The preceding description is intended to enable others skilled in the art to best utilize the principles in various embodiments and aspects and with various modifications as are suited to the particular use contemplated. It is intended that the scope of the invention be defined by the following claims.