Abstract:
Systems and methods for deploying and using a controlled-frequency downhole seismic source are provided. A downhole seismic source may be placed into a borehole in a geological formation and coupled rigidly to the geological formation via an edge of the borehole. A controlled-frequency seismic signal may be generated sufficient to enable a seismic measurement of the geological formation.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    This application claims the benefit of and priority to U.S. Provisional Patent Application Ser. No. 62/144,549, “Controlled-Frequency Downhole Seismic Source,” filed on Apr. 8, 2015, which is incorporated by reference herein in its entirety for all purposes. 
     
    
     BACKGROUND 
       [0002]    This disclosure relates to a downhole controlled-frequency seismic source that can output a relatively low-frequency oscillating seismic signal. 
         [0003]    This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present techniques, which are described and/or claimed below. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure. Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art. 
         [0004]    Seismic imaging may be used to identify characteristics or features of a geological formation. Among other things, these characteristics and features may include the presence or absence of certain lithological features, hydrocarbons, gases, and so forth. To obtain a seismic image, a seismic source may output a seismic signal into the geological formation. A seismic receiver may detect a resulting seismic signal that occurs after passing through the geological formation. Depending on the constituency of the geological formation, the receiver will detect certain variations in the seismic signal. Thus, the detected seismic signal may be used to determine certain properties of the geological formation, such as the lithology of the geological formation or the contents of a hydrocarbon zone in the geological formation. 
         [0005]    Seismic sources may be deployed on the surface of the geological formation or in a borehole. Many seismic sources are impulsive, using explosives or airguns to emit a seismic signal into the geological formation. In cases where a seismic source is deployed downhole, the seismic source may be coupled to the geological formation—that is, connected to the geological formation so as to permit force from the seismic source to be transmitted into the geological formation—using a fluid. This is referred to as “fluid coupling.” Although fluid coupling may be effective for impulsive seismic sources, fluid may absorb low-frequency seismic energy. Thus, many downhole seismic sources may not be able to adequately provide low-frequency seismic signals. 
       SUMMARY 
       [0006]    A summary of certain embodiments disclosed herein is set forth below. It should be understood that these aspects are presented merely to provide the reader with a brief summary of these certain embodiments and that these aspects are not intended to limit the scope of this disclosure. Indeed, this disclosure may encompass a variety of aspects that may not be set forth below. 
         [0007]    This disclosure relates to systems, methods, and devices for installing and/or using a downhole seismic source that can provide a controlled-frequency seismic signal into a geological formation. An example method includes placing a downhole seismic source into a borehole in a geological formation and coupling the downhole seismic source rigidly to the geological formation via an edge of the borehole. A controlled-frequency seismic signal may be generated that is sufficient to enable a seismic measurement of the geological formation. 
         [0008]    In another example, a downhole seismic source includes a housing and an actuator. The housing couples to a geological formation via an edge of a borehole in the geological formation. The actuator is attached to the housing and generates a controlled-frequency seismic signal of less than 500 Hz to enable a seismic measurement of the geological formation. 
         [0009]    In another example, a method includes generating an oscillating seismic signal having a frequency lower than 500 Hz using a downhole seismic source installed in a borehole in a geological formation. The seismic signal may be detected using a seismic receiver to enable a seismic measurement of the geological formation. 
         [0010]    Various refinements of the features noted above may be undertaken in relation to various aspects of the present disclosure. Further features may also be incorporated in these various aspects as well. These refinements and additional features may exist individually or in any combination. For instance, various features discussed below in relation to one or more of the illustrated embodiments may be incorporated into any of the above-described aspects of the present disclosure alone or in any combination. The brief summary presented above is intended just to familiarize the reader with certain aspects and contexts of embodiments of the present disclosure without limitation to the claimed subject matter. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0011]    Various aspects of this disclosure may be better understood upon reading the following detailed description and upon reference to the drawings in which: 
           [0012]      FIG. 1  is a schematic diagram of a seismic imaging system used for imaging a geological formation, in accordance with an embodiment; 
           [0013]      FIG. 2  is a schematic view of a controlled-frequency downhole seismic source that is rigidly coupled to the geological formation to enable the emission of a low-frequency signal into the geological formation, in accordance with an embodiment; 
           [0014]      FIG. 3  is a flowchart of a method for installing and using the a schematic view of the controlled-frequency downhole seismic source, in accordance with an embodiment; 
           [0015]      FIG. 4  is a block diagram of one example of the downhole seismic source of  FIG. 2 , in accordance with an embodiment; 
           [0016]      FIG. 5  is a block diagram of a voice coil actuator that may be used in the downhole seismic source, in which the voice coil has a moving coil assembly, in accordance with an embodiment; 
           [0017]      FIG. 6  is a block diagram of a voice coil actuator that may be used in the downhole seismic source, in which the voice coil has a moving permanent magnet assembly, in accordance with an embodiment; 
           [0018]      FIG. 7  is a is a block diagram of another example of the downhole seismic source that operates using feedback from a position sensor, in accordance with an embodiment; 
           [0019]      FIG. 8  is a block diagram describing components for controlling the downhole seismic source that may be located at the surface and those that may be located downhole, in accordance with an embodiment; 
           [0020]      FIG. 9  is a block diagram of an open-loop control system for controlling the downhole seismic source, in accordance with an embodiment; 
           [0021]      FIG. 10  is a block diagram of a closed-loop control system for controlling the downhole seismic source, in accordance with an embodiment; 
           [0022]      FIG. 11  is a block diagram of another example of a downhole seismic source that includes more than one actuator, in accordance with an embodiment; 
           [0023]      FIG. 12  is a schematic diagram of an example of a downhole seismic source that produces a horizontal seismic signal, in accordance with an embodiment; and 
           [0024]      FIG. 13  is a perspective view of a layout of multiple installed downhole seismic sources that are supplied with power from a power grid, in accordance with an embodiment. 
       
    
    
     DETAILED DESCRIPTION 
       [0025]    One or more specific embodiments of the present disclosure will be described below. 
         [0026]    These described embodiments are just examples of the presently disclosed techniques. Additionally, in an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions may be made to achieve the developers&#39; specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure. 
         [0027]    When introducing elements of various embodiments of the present disclosure, the articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. 
         [0028]    As mentioned above, seismic imaging may be used to identify characteristics or features of a geological formation. Among other things, these characteristics and features may include the presence or absence of certain lithological features, hydrocarbons, gases, and so forth. One manner of obtaining seismic information may be through a controlled-frequency downhole seismic source. 
         [0029]    This disclosure describes a controlled-frequency downhole seismic source that may be able to provide a controlled-frequency seismic signal (e.g., a vibration signal of defined frequency or frequencies). Rather than rely on fluid coupling, the controlled-frequency downhole seismic source of this disclosure may be rigidly coupled to the geological formation. As used herein, the expression “rigidly coupled” refers to any suitable coupling that is rigid enough not to absorb too much of the output seismic signal in the frequency range of interest. For example, the controlled-frequency downhole seismic source may emit a relatively low-frequency seismic signal of less than about 500 Hz. Indeed, in some examples, the relatively low-frequency seismic signal may be less than 100 Hz, less than 10 Hz, or even about or less than 1 Hz owing to the rigid coupling of the seismic source to the geological formation. The coupling mechanism for the controlled-frequency downhole seismic source may be a heavy pipe, a heavy weight, cams, wedges, or clamps, and so forth, that do not absorb too much of the seismic signal, but instead allow the controlled-frequency downhole seismic source to output the seismic signal into the geological formation. 
         [0030]    Such a controlled-frequency downhole seismic source may be used, for example, a seismic imaging system  10  as shown in  FIG. 1 . The seismic imaging system  10  may be used to image a geological formation  12  that includes, in the example of  FIG. 1 , a hydrocarbon zone  14  or other geological region of interest. A borehole  16  may be drilled into the hydrocarbon zone  14 . A downhole tool  18  may be used to gather information from time to time. In one example, the downhole tool  18  may include seismic receivers that can detect seismic signals from other seismic sources. 
         [0031]    A controlled-frequency downhole seismic source system  20  may be used to emit a seismic signal into the geological formation  12 . Here, the controlled-frequency downhole seismic source system  20  includes a downhole seismic source  44  installed in an investigation borehole  22 . The borehole  22  extends to below a weathering layer  24  and/or other acoustically attenuating geological layers. Because the weathering layer  24  and other surface conditions might otherwise absorb seismic energy, installing the downhole seismic source  44  below the weathering layer  24  may allow the controlled-frequency downhole seismic source system  20  to emit a controlled-frequency seismic signal  26  (e.g., vibration) of much better quality into the geological formation  12 . As may be appreciated, the weathering layer  24  and other surface conditions might otherwise absorb seismic energy and, accordingly, reduce the bandwidth of the seismic signal  26 . Moreover, the weathering layer  24  may pose a challenge to repeat measurements over time. Thus, by placing the downhole seismic source  44  beneath the weathering layer  24 , these problems may be reduced or avoided. Surface equipment  28  may control and power the controlled-frequency downhole seismic source system  20 . 
         [0032]    A variety of seismic receivers, such as buried seismic receivers  30 , surface seismic receivers  32 , and/or seismic receivers in the downhole tool  18  may detect the controlled-frequency seismic signal  26  after it has traveled through the geological formation  12 . Different features and characteristics of the geological formation  12  may affect the controlled-frequency seismic signal  26  in different ways (e.g., by absorbing the signal, scattering the signal, refracting the signal, reflecting the signal, and so forth). As a result of these interactions, geological features and characteristics of the geological formation  12  may be identified through any suitable seismic imaging techniques. It may be appreciated that other seismic receivers and sources may also be used in the seismic imaging system  10 . One non-limiting example may be a vehicle-based seismic imager  34 , which may be a seismic source or receiver, or both, though any other suitable sources and receivers may also be used. 
         [0033]    The seismic imaging system  10  may use the controlled-frequency downhole seismic source system  20  to conduct seismic investigation of the geological formation  12  over time. Indeed, the controlled-frequency downhole seismic source system  20  may be used to operate continuously or intermittently for long or short periods of time (e.g., a few minutes, a few hours, a few days, a few weeks, months, or even years). This may allow for characterization and/or long term monitoring of reservoirs that otherwise might not be possible or cost-effective. Indeed, the controlled-frequency downhole seismic source  20  may serve as a consistently similar source that can calibrate arrays of seismic sensors deployed to monitor hydraulic fractures, as well as naturally occurring seismic events and induced seismicity. 
         [0034]    A block diagram of the controlled-frequency downhole seismic source system  20  appears in  FIG. 2 . In the example of  FIG. 2 , the borehole  22  has been drilled and completed. A casing  40  of any suitable material lines the borehole  22 . A coupling mechanism  42 , such as pipe that may have been used in the initial installation of the downhole seismic source  44 , may rigidly couple the downhole seismic source  44  to the borehole. A cable  46  may supply electricity and/or control signals from the surface equipment  28  to the downhole seismic source  44 . 
         [0035]    Any suitable coupling mechanism may be used to rigidly couple the downhole seismic source  44  to the geological formation  12 . In the example shown in  FIG. 2 , the coupling mechanism is pipe  42  that presses the downhole seismic source  44  against the bottom of the borehole  22  using the weight of the mass of the pipe. To this end, the coupling mechanism may be any suitable mechanism to rigidly press the downhole seismic source  44  to the geological formation  12 . Others may include clamps, cams, weight bars, wedges, gravity, and so forth. Any materials that are sufficiently rigid so as to act as a counterforce to relatively low frequency seismic signals that are generated by the downhole seismic source  44  may serve as the coupling mechanism  42 . 
         [0036]    The controlled-frequency downhole seismic source system  20  may be installed as described by a flowchart  50  of  FIG. 3 . That is, the investigation borehole  22  may be drilled to beneath the weathering layer  24  of the geological formation  12  (block  51 ). The borehole  22  may be cased with a casing  40  (block  52 ). It may be appreciated that, in some embodiments, the borehole  22  may not be cased with casing  40 . The borehole  22  may be vertical in one example, but also may be at least partially horizontal in other examples. 
         [0037]    The downhole seismic source  44  may be deployed into the borehole  22  using any of a variety of ways. For example, deployment of the downhole seismic source  44  to depth may be achieved using cable, tubing, casing, drill pipe, or coiled tubing (block  53 ). The downhole seismic source  44  may be rigidly coupled to the casing  40  and/or the bottom of the borehole  22  (block  54 ). For example, the equipment used in the different deployment methods may allow their weight to be used to couple the downhole seismic source  44  to the geological formation  12 . As noted above, deployment to depth can also be achieved using a cable containing conductors or a cable with conductors attached alongside. To utilize gravity for coupling with cable deployment, additional weights (e.g., weight bars) may be attached between the cable and the downhole seismic source  44 . Additional materials that may couple the downhole seismic source  44  to the casing  40  and/or the bottom of the borehole  20  may include cams, wedges, clamps, and so forth. Moreover, when the downhole seismic source  44  is deployed and coupled to the geological formation  12  using sections of pipe  42 , the pipe  42  may be filled with cement to add additional weight, and may extend substantially to the surface or just partway. The downhole seismic source  44  may be considered to be sufficiently rigidly coupled to the geological formation  12  when the downhole seismic source  44  is able to output the controlled-frequency seismic signal  26  into the geological formation  12  without the signal being substantially attenuated by the coupling mechanism (e.g., as might occur with fluid coupling). 
         [0038]    Having installed the downhole seismic source  44  into the borehole  20  and coupled the downhole seismic source  44  to the geological formation  12 , the downhole seismic source  44  may be used to generate the controlled-frequency seismic signal  26  (block  55 ). To generate the controlled-frequency seismic signal  26 , the downhole seismic source  44  may operate an actuator  60  attached to a housing  62 , as shown in  FIG. 4 . The actuator  60  may move a shaft  64  to apply a force to a reaction mass  66 . Because the housing  62  of the downhole seismic source  44  is rigidly coupled to the geological formation  12 , the movement of the actuator  60  and the equal and opposite reaction to the force by the reaction mass  66  causes the housing  62  to impart the force into the geological formation  12  as the seismic signal  26 . Bearings (not shown) may be used to reduce friction caused when the actuator  60  moves the reaction mass  66 . The bearings may be particularly helpful when the actuator  60  is disposed wholly or partly horizontally. 
         [0039]    The actuator  60  may be pneumatic, piezoelectric, hydraulic, magnetorestrictive, and/or electromagnetic, and/or may use any other suitable actuation mechanism. The actuator  60  may move the shaft  64  over a range of motion (e.g., +/−1.5 inches) forward and backward in relation to an axis of the actuator  60  at a desired frequency (e.g., when the actuator  60  is oriented vertically, the actuator  60  may move the shaft  64  up and down). The frequency of the motion of the actuator  60  is substantially the frequency of the output seismic signal  26 . Control and power signals may be provided via the cable  46 . 
         [0040]    Tubing or pipe  42  may provide enough weight on the downhole seismic source  44  to rigidly couple the downhole seismic source  44  to the geological formation  12 . In one example, tubing or pipe  42  may extend to the surface and be weighted by a rig and/or other deployment devices. The tubing or pipe  42  may be filled with a weight-adding material, such as cement, and may or may not extend to the surface. In at least one embodiment, the tubing or pipe  42  may be retrievable (e.g., after the downhole seismic source  44  is installed or upon removal of the downhole seismic source  44  after its use). 
         [0041]    A positioning system  68  may be used to ensure the actuator  60  is operating over the desired range of motion. In the example of  FIG. 4 , the positioning system  68  includes two permanent magnets  70  and  72  that apply increasingly more force the closer the permanent magnets  70  and  72  are placed to one another. Depending on the distance that the shaft  64  is extended out of the actuator  60 , a particular level of force may occur due to the proximity of the permanent magnets  70  and  72 . A first amount of force from the permanent magnets  70  and  72  may be associated with a center of the desired range of motion and a second amount of force from the permanent magnets  70  and  72  may be associated with an endpoint of the range of motion. Although the positioning system  68  shown in  FIG. 4  uses permanent magnets, springs, position sensors, and the like may also be used to maintain a relatively consistent range of motion of the actuator  60 . 
         [0042]    As mentioned above, the actuator  60  may operate using electromagnetism and, as such, may be a voice coil.  FIGS. 5 and 6  show examples of voice coils that may be used as the actuator  60 . In  FIG. 5 , a moving coil assembly  74  is radially surrounded by a fixed permanent magnetic field assembly  76 . The moving coil assembly  74  includes a center shaft  78  that is wrapped by a coil of conductive wire  80 . When current is applied to the conductive wire  80 , an electromagnetic field causes the moving coil assembly  74  to repel or attract the fixed permanent magnetic field assembly  76 . This causes the moving coil assembly  74  to move in or out depending on the polarity of the current. 
         [0043]    The voice coil actuator  60  shown in  FIG. 6  uses a stationary coil assembly  82  and a moving permanent magnetic field assembly  84 . The stationary coil assembly  82  includes the coil of conductive wire  80 . When current is applied to the conductive wire  80 , an electromagnetic field causes the stationary coil assembly  82  to repel or attract the moving permanent magnetic field assembly  84 . This causes the moving permanent magnetic field assembly  84  to move in or out depending on the polarity of the current. 
         [0044]    As shown in  FIG. 7 , a position encoder  90  may be used to determine a position of the actuator  60 . The position encoder  90  may use any suitable sensor to determine a position of the actuator  60  by monitoring a position of the shaft  64 . For example, the position encoder  90  may be a capacitive sensor, an inductive sensor, a magnetoresistive sensor, an LVDT sensor, an optical sensor, a time-domain reflectance sensor, or mechanical sensor (e.g., a linkage). The position determined by the position encoder  90  may be used to control the actuator  60 . For instance, a position signal  92  may be compared to a reference position control signal from the cable  46  in an operational amplifier  94  or comparable circuitry (e.g., digital comparator). A control signal  96  may be generated to control the actuator  60  to maintain its operation within the desired range of motion. 
         [0045]      FIG. 8  illustrates a general topology of a seismic source control system  100  to control the downhole seismic source  44 . The system  100  of  FIG. 8  locates motion controller  102  electronics, a drive amplifier  104 , and line receiver decoding  106  among the surface equipment  28 . Subsurface equipment  108  within the borehole  22  include the voice coil  60  (e.g., the voice coil motor), which is coupled to the moving mass  66  via the shaft  64 , the position encoder  90  (e.g., position encoder), and line driver encoding  110 . Cabling and/or wires convey power signals and electrical control signals (e.g., power signal  112  and the position signal  92 ) between the surface equipment  28  and the subsurface equipment  108 . It should be appreciated, however, that the surface equipment  28  may be located downhole with the subsurface equipment  108 , provided that energy is provided to these components from the surface. 
         [0046]    The motion controller  102  provides a command signal to the drive amplifier  104 , which activates the voice coil  60 , resulting in mass  66  motion. The position encoder  90  measures the absolute position of the moving mass  66 . This position data is fed back to the motion controller  102  via the line driver encoding  110 —line receiver decoding  106  and made available to the motion controller  102 . The moving mass  66  vibratory operational range may be from 10 to 500 Hz, but may be higher or lower in other examples. In one example, the electro-mechanical transfer function of the moving mass  66  and the voice coil  60  may a factor of  100  reduction in mechanical movement given constant applied voice coil RMS power over the range of 10 to 100 Hz. 
         [0047]    The moving mass  66  weight (and/or an accompanying centering spring) may be selected such that for maximum applied voice coil  60  power at the lowest operating frequency, shaft  64  excursions are constrained to near voice coil  60  operational limits. (For a given input power and frequency, increasing the moving mass  66  weight reduces movement of the shaft  64  of the voice coil  60 .) However, this value of weight may preclude any appreciable shaft  64  movement at the highest desired operating frequency. To allow operation at higher voice coil  60  operating frequencies, the shaft  64  weight may be reduced and, correspondingly, the voice coil  60  input power reduced at low operating frequencies to limit shaft  64  excursions. Thus, the allowed voltage applied to the voice coil  60  may be a function (e.g., a complex function) that may be limited by, for example: 1.) shaft  64  excursion, 2.) frequency of operation, 3.) maximum allowed applied voltage, and/or 4.) maximum voice coil power. A motion profile  114 , which may be carried out by the motion controller  102 , may be tailored and limited by these parameters. Indeed, it should be appreciated that the motion controller  102  may include any suitable circuitry (e.g., an application-specific integrated circuit (ASIC), a programmable logic device (PLD), a processor and memory) that may carry out the motion profile  114 . For instance, the motion profile  114  may represent instructions encoded on a tangible, non-transitory article of manufacture, such as a memory device, that may be executed by the motion controller  102 . 
         [0048]      FIG. 9  shows a seismic source control system  120  that uses an open loop topology. The motion controller  102  contains a defined motion profile  114  that may be loaded into an excitation profile store  122 . The excitation profile store  122  may be any suitable tangible, non-transitory article of manufacture, such as a memory device, that may store the motion profile  114  for execution by the motion controller  102 . The motion profile  114  may define a desired motion of the moving mass  66  and may take a generally sinusoidal form (e.g., sweep, chirp). The output of the motion controller  102  may be a control signal C(t) that is the command to the drive amplifier  104 . The drive amplifier  104  produces the voice coil terminal voltage V(t), constrained by a maximum voltage Vlimit and subject to an RMS Watt limit  124  that folds back the drive amplifier  104  in case of excessive motion profile  114  drive. A position encoder  90  converts shaft  64  movement to an electrical signal F(t) that is made available to the motion controller  102 . In addition to mechanical spring shaft  64  centering, a DC offset  126  may be applied via summation  128  prior to motion profile  114  execution/output of the control signal C(t) based upon F(t). A motion monitor  130  component of the motion controller  102  may ensure that the motion of the moving mass  66  remains within acceptable limits. 
         [0049]    The maximum magnitude of the motion profile  114  may be determined at each operating frequency by the motion controller  102  such that the following parameters are constrained by, for example, 1.) F(t) (shaft  64  limits), 2.) V(t) (breakdown voltage), and/or 3.) RMS Watts (heating). Once the magnitude of the motion profile  114  is determined as a function of operating frequency, the motion profile  114  may be assembled and executed by the system  120  to output a seismic signal into the geological formation  12 . 
         [0050]      FIG. 10  shows a seismic source control system  140  that uses a closed loop control topology. In  FIG. 10 , the motion controller  102  contains a defined motion profile  114  that may be loaded into the excitation profile store  122 . As in the system  120  discussed above, the excitation profile store  122  of the system  140  may also be any suitable tangible, non-transitory article of manufacture, such as a memory device, that may store the motion profile  114  for execution by the motion controller  102 . The motion profile  114  may define a desired motion M(t) of the moving mass  66  and may take a generally sinusoidal form (e.g., sweep, chirp). The motion controller  102  performs certain operations, discussed further below, to produce a control signal C(t) which is the command to the drive amplifier  104 . 
         [0051]    The drive amplifier  104  produces the voice coil motor  60  terminal voltage V(t), constrained by a maximum voltage Vlimit and subject to an RMS Watt limit  142  that folds back the drive amplifier  104  in case of excessive motion profile  114  drive. The position encoder  90  converts shaft  64  movement to an electrical signal F(t), which is made available to the motion controller  102 . In addition to mechanical spring shaft  64  centering, a DC offset  126  may be applied via summation  128  prior to motion profile  114  execution/output of the control signal C(t) based upon F(t). The shaft  64  motion is constrained by a fixed peak limiting value Pk_Limit, which describes a maximum desired peak of the motion of the moving mass  66 . 
         [0052]    Moving mass  66  absolute position data F(t) are input to a peak-to-peak detection component  144  of the motion controller  102 . The peak-to-peak detection component  144  computes the difference between the last positive and negative input values per cycle resulting in a signal F(t_pk). F(t_pk) is compared to the fixed peak limiting value Pk_Limit at summation logic  146  and this difference passed to an integrator  148  with gain K, attack time constant tau 1 , and release time constant tau 2   150 . Time constant tau 1  may be less than time constant tau 2 . The integrator  148  output is constrained to the region of 0 and unity. The output of the integrator  148  is fed to a multiplier  152 , which acts upon M(t) to produce C(t) (after the initial centering offset via the summation  128 ). If shaft  64  motion becomes excessive, F(t_pk) exceeds PK_Limit and the integrator  148  output is reduced, thus reducing C(t). If F(t_Pk) is less than PK_Limit, M(t) is not effected by the integrator  148  output. 
         [0053]    Multiple actuators  60  (e.g.,  60 A and  60 B) may be used, as shown in  FIG. 11 . Moreover, the reaction mass  66  may be located above or below the actuators  60 , and the position system  68  may include a spring  92 . It should be appreciated that the components shown in  FIG. 11  may be used in other configurations. The configuration of  FIG. 11  is shown by way of example to illustrate that these components of the downhole seismic source  44  may take other configurations than those expressly shown in this disclosure. 
         [0054]      FIG. 12  shows an example of a horizontal-signal-producing configuration  100  of a downhole seismic source  44 . A housing  102  includes linkages  104  with joints  106  that Couple the horizontal motion of the downhole seismic source  44  into Horizontal motion against the geological formation  12  using the same vertical force applied from above by weights or pipe. The vertical force from above is converted to a horizontal force against the formation using a spring and sliding joint  108 , linkages  102  and  104  and pivots  106 . That is, the orientation of the actuator  60  within the downhole seismic source  44  in the configuration  100  may be substantially horizontal, rather than vertical as shown in other configurations above. In other words, the actuator  60  may be turned on its side to produce shear waves towards the direction of the reservoir. The linkages  102  and  104 , pivots  106  and arms translate the hold-down weight of the pipe  42  to a horizontal force to couple the horizontal force from the actuator  60  into the geological formation  12 . 
         [0055]      FIG. 13  shows that multiple devices can be deployed within a field and powered by generators or grid power. Autonomous operation may be achieved using wireless communications to the Internet for display of monitor and control of functionality. For increased output, multiple devices can be operated in parallel, side by side, or stacked vertically in the same hole or in multiple holes drilled in close proximity. 
         [0056]    The specific embodiments described above have been shown by way of example, and it should be understood that these embodiments may be susceptible to various modifications and alternative forms. It should be further understood that the claims are not intended to be limited to the particular forms disclosed, but rather to cover all modifications, equivalents, and alternatives falling within the spirit and scope of this disclosure.