Patent Publication Number: US-2017371048-A1

Title: Buried seismic sensor and method

Description:
PRIORITY INFORMATION 
     The present application claims priority under 35 U.S.C. §119(e) to U.S. Provisional Patent Application Ser. No. 62/117,467, filed Feb. 18, 2015, the entire contents of which are expressly incorporated herein by reference. 
    
    
     TECHNICAL FIELD 
     The present embodiments relate generally to land seismic exploration systems and methods, and more specifically to systems and methods for receivers used in land seismic exploration systems. 
     BACKGROUND 
     Seismic waves generated artificially have been used for more than 50 years to perform imaging of geological layers. During seismic exploration operations, vibrator equipment or dynamite (also known as a “source”) generates a seismic signal that propagates in the form of a wave that is reflected at interfaces of geological layers. For land seismic surveying, these reflected waves are typically received by geophones, or more generally “receivers,” which convert the displacement of the ground resulting from the propagation of the waves into an electrical signal which is recorded. Analysis of the arrival times and amplitudes of these waves make it possible to construct a representation of the geological layers on which the waves are reflected. 
       FIG. 1  depicts schematically a system  100  for transmitting and receiving seismic waves intended for seismic exploration in a land environment. System  100  includes a source  102  consisting of a vibrator operable to generate a seismic signal, a set of receivers  104  for receiving a seismic signal and converting it into an electrical signal and a recorder  106  (or central station) for storing the electrical signals generated by the receivers. Source  102 , receivers  104  and recorder  106  are positioned on the surface of the ground  108 .  FIG. 1  depicts source  102  as a single vibrator, but it should be understood that the source may be composed of several vibrators, as is well known to persons skilled in the art. 
     In operation, source  102  is operated to generate a seismic signal. This signal propagates firstly on the surface of the ground (known as ground roll or Rayleigh waves), in the form of surface waves  110 , and secondly in the subsoil, in the form of transmitted waves  112  that generate reflected waves  114  when they reach an interface  115  between two geological layers  116  and  118 . In a solid medium, the waves radiated by a source (transmitted waves  112 ) are a combination of P-waves (pressure waves) and S-waves (shear waves). P-waves produce, as they pass through the media, localized volumetric changes in the media while S-waves produce a localized distortion in the media with corresponding particle motion. 
     The surface wave  110  produces a retrograde particle motion in the soil, but there is no local volumetric change associated with it as it propagates. The propagation velocity for surface waves and S-waves is much less than for P-waves. Typically, the fraction of P-wave radiated energy from a surface source is about 8%, with surface waves and S-waves comprising the remaining 92% of the total radiated wave energy. Surface waves  110 , decay with depth, but they decay more slowly at low frequencies, so they can still have significant amplitude even at 100 m depth for example. 
     Each receiver  104  receives both a surface wave  110  and a reflected wave  114  and converts them into an electrical signal, which signal thus includes a component associated with the reflected wave  114  and another component associated with the surface wave  110 . Since system  100  intends to image the subsurface layers  116  and  118 , including a hydrocarbon deposit  120 , the component in the electrical signal associated with the surface wave  110  is undesirable and should be filtered out. In general, most reflection seismology today use the reflection data associated with P-wave emissions and their reflections. In many cases, S-waves are not used and oftentimes treated as another undesired source of coherent noise. For the case of reservoir monitoring, where a high degree of repeatability may be required, it should be noted that source  102  may be a buried source rather than a surface source. One such reservoir monitoring system that employs buried sources is described in U.S. Pat. No. 6,714,867. Buried receivers can also be useful for monitoring/imaging other oil-field processes like fracture monitoring, where the receiver is located closer where a microseismic event might be created by fluid injection; or for passive seismic monitoring in which case the seismic source may be drills, natural phenomena like earthquakes or ocean tides. 
     Historically, land seismic systems  100  have typically employed geophones as receivers  104 . A geophone is a device that converts ground movement into voltage. Geophones use either a spring mounted magnetic mass or a spring mounted coil. More recently an analogous MEMS device has been introduced. The deviation of this measured voltage from a base line is the seismic response which can be analyzed to image the subsurface regions  116 ,  118  and  120 . By way of contrast, hydrophones have typically been employed for marine seismic systems. A hydrophone is essentially a microphone designed to be used underwater for recording or listening to underwater sound. Most hydrophones are based on a piezoelectric transducer that generates electricity when subjected to a pressure change. Such piezoelectric materials or transducers can convert a sound signal into an electrical signal since sound is a pressure wave. Although geophones have typically been used as receivers  104  in land seismic operations, and hydrophones have typically been used as receivers in marine seismic operations, in certain cases these roles have been reversed and indeed today some seismic systems are being designed to use both types of sensors as receivers. 
     Reservoir monitoring systems are becoming more common. 4-D survey techniques are used to detect subtle changes in seismic images over time. Changes in the reservoir image are useful for detecting changes in reservoir fluid volumes and their locations. This information is useful for enhanced recovery of hydrocarbons, for example, by providing information to operators that pumping schedules need to be adjusted either for fluid extraction or injection or to help decide if other processes to improve fluid communication need to be applied. 
     Because the data in these instances is for 4-D studies, with the fourth dimension being time, subtle changes in seismic images over time are monitored. This monitoring requires that factors like soil temperature or soil moisture content not affect the image. By cementing the receivers in place at depth, changes in acoustic properties in the media and changes in coupling to the formation, due to rain and other factors is mitigated. In some places, sources are buried at depth and cemented into the formation. In other cases, surface sources like seismic vibrators are used. In many cases, the vibrators operate on pads that may be poured concrete or other surface preparation to improve repeatability, by fixing the surface source position and coupling with the medium. 
     Because of cost constraints, the number of cemented/buried receivers is limited. Consequently, processing methods typically used in conventional reflection seismology for removal of unwanted coherent noise, like Rayleigh waves, cannot be used in many cases. Buried receivers in the past have been primarily geophones, which detect particle velocity and are sensitive to both body waves and Rayleigh waves/ground roll. So receivers that are relatively insensitive to Rayleigh waves but still can detect body waves like P-waves and/or S-waves would be helpful. Recently, buried hydrophones have been introduced as a means for detecting body waves in solids. Hydrophones are high output impedance devices and typically require either a charge amplifier or transformer to provide a signal compatible with standard seismic acquisition systems. Hydrophones also tend to be omnidirectional devices, so they are just as sensitive to P-waves traveling horizontally as to reflected waves coming from interfaces at depth that are of greatest interest. 
     Therefore, there is a need for a new seismic sensor that is less sensitive to coherent noise like Rayleigh waves, has low intrinsic output impedance and is directional. 
     SUMMARY 
     An aspect of the embodiments is to substantially solve at least one or more of the problems and/or disadvantages discussed above, and to provide at least one or more of the advantages described below. 
     It is therefore a general aspect of the embodiments to provide a seismic device for recording seismic waves. The device includes a housing to be located in a fill-in material and/or a formation; a first assembly located inside the housing; and a first anchor attached to the first assembly and exiting through the housing to contact the fill-in material and/or the formation. The first assembly is configured to measure a quantity indicative of a strain experienced by the formation due to the seismic waves. 
     In one aspect, there is a seismic device for recording seismic waves. The device includes a housing to be embedded in a fill-in material and/or a formation; a first magnetic assembly located inside the housing; a second magnetic assembly located inside the housing; and a rigid member located inside the housing and separating the first magnetic assembly from the second magnetic assembly. The first and second magnetic assemblies generate corresponding first and second voltages, a difference of which is indicative of a strain experienced by the formation due to the seismic waves. 
     According to another aspect, there is a method for determining a time derivative of a strain in a fill-in material and/or formation. The method includes placing a seismic device in a well; filling the well with the fill-in material so that the seismic device is surrounded by the fill-in material; generating a seismic wave with a seismic source; and measuring a quantity indicative of a strain in the fill-in material and/or the formation with the seismic device, wherein the strain in the fill-in material and/or the formation is a result of the seismic wave passing through the fill-in material and/or the formation. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The above and other aspects and features of the embodiments will become apparent and more readily appreciated from the following description of the embodiments with reference to the following figures, wherein like reference numerals refer to like parts throughout the various figures unless otherwise specified, and wherein: 
         FIG. 1  depicts schematically a device for transmitting and receiving seismic waves intended for seismic exploration in a land environment; 
         FIG. 2  is a flowchart of a method for acquiring and processing seismic data; 
         FIG. 3  illustrates a seismic sensor that determines a time derivative of a strain in a formation; 
         FIG. 4  illustrates a coil of the seismic sensor of  FIG. 3 ; 
         FIG. 5  illustrates another seismic sensor that determines a time derivative of a strain in a formation; 
         FIG. 6  illustrates yet another seismic sensor; 
         FIG. 7  illustrates still another seismic sensor that determines a time derivative of a strain in a formation; 
         FIG. 8  illustrates a seismic sensor that uses a piezoelectric assembly for determining a time derivative of a strain in a formation; 
         FIG. 9  illustrates the piezoelectric assembly; 
         FIG. 10  illustrates a seismic sensor that uses a transducer assembly for determining a strain in a formation; 
         FIGS. 11A-B  illustrate the transducer assembly; 
         FIG. 12  illustrates a multi-component seismic sensor; and 
         FIG. 13  is a flowchart of a method for measuring the time derivate of a strain in a formation. 
     
    
    
     DETAILED DESCRIPTION 
     The embodiments are described more fully hereinafter with reference to the accompanying drawings, in which embodiments of the novel concept are shown. In the drawings, the size and relative sizes of layers and regions may be exaggerated for clarity. Like numbers refer to like elements throughout. The embodiments may, however, be embodied in many different forms and should not be construed as limited to the embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be complete, and will convey the scope of the associated concepts to those skilled in the art. It will be apparent to one skilled in the art, however, that at least some embodiments may be practiced without one or more of the specific details described herein. In other instances, well-known components or methods are not described in detail or are presented in simple block diagram format in order to avoid unnecessarily obscuring the embodiments. The scope of the embodiments is therefore defined by the appended claims. The following embodiments are discussed, for simplicity, with regard to the terminology and structure of a land seismic exploration system, but are not necessarily limited thereto. 
     Reference throughout the specification to “one embodiment” or “an embodiment” means that a particular feature, structure, or characteristic described in connection with an embodiment is included in at least one embodiment of the present embodiments. Thus, the appearance of the phrases “in one embodiment” on “in an embodiment” in various places throughout the specification is not necessarily referring to the same embodiment. Further, the particular feature, structures, or characteristics may be combined in any suitable manner in one or more embodiments. 
     As mentioned above in the Background section, it would be desirable to overcome some of the various problems and difficulties associated with seismic sensors used in seismic acquisition, and in particular, where such seismic sensors are used, for example, in 4D land seismic acquisition. The following embodiments address this challenge by, among other things, providing a new seismic device that has a coil-magnet system that is capable of measuring a time derivative of a strain in a subsurface formation. Other embodiments, described below, address the same or similar challenges using different configurations. Some of the embodiments discussed herein measure directly the strain and not its derivative. In one application, it is possible to measure the second derivative of the strain and then estimate the strain. In other words, the embodiments discussed herein measure a quantity indicative of the strain and this quantity can be the strain itself, the first derivative of the strain, the second derivative of the strain or any other parameter from which the strain may be estimated. 
     Prior to describing such seismic sensor according to embodiments in more detail, an additional brief discussion of the overall seismic exploration or acquisition process will first be provided for context. As generally discussed above, one purpose of seismic exploration is to render the most accurate graphical representation (e.g., image) possible of specific portions of the Earth&#39;s subsurface geologic structure, e.g., using the data which is collected as described above with respect to  FIG. 1 . The images produced allow exploration companies to accurately and cost-effectively evaluate a promising target (prospect) for its oil and gas yielding potential (e.g., hydrocarbon deposit  120 ).  FIG. 2  illustrates a generalized method for seismic exploration which includes both the acquisition of the seismic data described above, and the subsequent processing of that seismic data to form such images. In  FIG. 2 , the overall process is broken down into five steps, although one could of course characterize seismic exploration in a number of different ways. Step  200  references the initial positioning of the survey equipment in the geographic area of interest (GAI) and the preparation to begin surveying the GAI in a manner which is precise and repeatable. Seismic waves are generated in step  202  by the afore-described sources or vibrators, and data recording is performed in step  204  on the direct, refracted, reflected, scattered and surface waves (note that surface waves may propagate not only at the surface as direct waves, but also at layer interfaces if there is a change in the acoustic impedance) by the seismic sensors. As will be appreciated, the seismic sensors according to the embodiments described below, can be envisioned as impacting both steps  200  and  204 , since they will, for example, be positioned in respective boreholes and also perform part of the step of recording the data in their roles as receiver/transducer. 
     In step  206 , processing of the raw, recorded seismic data occurs. Data processing generally involves numerous processes intended to, for example, remove noise and unwanted arrivals/reflections from the recorded data and involves a significant amount of computer processing resources, including the storage of vast amounts of data, and multiple processors or computers running in parallel. Such data processing can be performed on site, back at a data processing center, or some combination thereof. Finally, in step  208 , data interpretation occurs and the results can be displayed or generated as printed images, sometimes in two-dimensional form, more often now in three dimensional form. Four dimensional data presentations (i.e., a sequence of 3D plots or graphs over time) are also possible outputs, when needed to track the effects of, for example, extraction of hydrocarbons from a previously surveyed deposit 
     With this context in mind, an embodiment of a buried seismic sensor is now discussed with respect to  FIG. 3 . A land seismic system such as that illustrated and described above with respect to  FIG. 1  can be used in conjunction with seismic sensor embodiments described herein, with the exception that boreholes  302 , each of which contain a separate buried seismic sensor  300 , provide seismic wave reception capability as opposed to receivers  104  being disposed on the surface of the area to be surveyed. As those of skill in the art can appreciate, additional boreholes  302  can be included in a given implementation with respective seismic sensors  300  to cover a desired GAI. In one embodiment, sensor(s)  300  can be used with hydrophones, geophones and/or accelerometers for collecting seismic data. 
     In this embodiment, the buried seismic sensor  300 , as shown in  FIG. 3 , includes a housing  310  that is placed in borehole  302 . Those skilled in the art would understand that borehole  302  may simply be a hole, a ditch, a well or any depression in the ground. The borehole may be vertical, horizontal or slanted. In one application, a depth H of a bottom of hole  302  from the surface  304  is between 3 and 50 m. In one embodiment, borehole  302  includes a single seismic sensor  300 . In another embodiment, borehole  302  includes plural seismic sensors  300 . In another embodiment, the seismic sensor  300  is buried vertically in borehole  302  and the borehole is backfilled with a given material  320 , e.g., cement, concrete, sand, clay, etc. In another embodiment, the seismic sensor is tilted inside the borehole or the borehole itself is tilted. 
     Housing  310  may be made of a material, e.g., plastic, that prevents humidity and/or impurities from the well entering the seismic sensor, and also has a rigid structure. Other materials than plastic may be used. The housing also needs to be stiff enough not to collapse under the pressure of the fill-in material, but have an elastic modulus much less than the fill-in material so that anchors  340  and  360 , to be discussed later, move with the formation  305  and/or the fill-in material and are not constrained by the housing. Housing  310  hosts an upper magnet assembly  330  and a lower magnet assembly  350 , each capable of measuring an electromagnetic force (EMF) induced by the relative movement of a magnet relative to a coil. This movement originates from a seismic wave interacting with the housing  310 . The two magnet assemblies  330  and  350  are configured to measure a time derivative of the strain generated by the seismic wave in borehole  302 . The magnet assemblies measure the time derivative of the strain (i.e., strain rate) of the fill-in material and/or the formation  305 . In one embodiment, this is achieved without fill-in material  320 , by cementing anchors (to be discussed later directly to the formation). 
     The upper magnet assembly  330  may be equipped with a magnet  332  sandwiched between ferromagnetic pole piece  333 . Magnet  332  is surrounded by upper coil  334 . Magnet  332  may include one or more magnets. Upper coil  334  has its bobbin encapsulated within coil holder  336 , which is ferromagnetic. As the coil bobbin is non-ferromagnetic, the coil holder completes the magnetic circuit. Note that there is a small circumferential air gap  338  between magnet  332  and coil  334  to permit the free motion of the magnet relative to the upper coil. In the embodiment discussed herein, the coil is fixed relative to the housing while the magnet moves relative to the upper coil. In another embodiment, it is possible to have the magnet fixed to the housing and the upper coil free to move. In still another embodiment, the gap  338  could be filled with grease or compliant elastomer or a slick bushing, for example, made from Teflon material. 
     In this embodiment, upper coil  334  is illustrated as a single device having a number of turns N. However, in one application, upper coil  334  is made of two coils  334 A and  334 B, which are turning in opposite directions as illustrated in  FIG. 4 . This arrangement is called a hum bucking coil and can be used for rejecting certain frequencies (e.g., 50 or 60 Hz) that are associated with the power grid. 
     In this embodiment, coil holder  336  is rigidly attached to upper anchor  340 , which is encased in fill-in material  320 . Upper anchor  340  is shown in  FIG. 3  as a rigid plate. However, it can be a flange, or a metal pipe or some other rigid material for attaching coil holder  336  to fill-in material  320 . Upper anchor  340  is shown penetrating housing  310  and extending into fill-in material  320 . In one embodiment, it is possible that upper anchor  340  is fixedly attached to housing  310 , without existing the housing. A pair of wires  342  is attached to upper coil  334  and the wires are exiting the borehole for communicating the induced voltage to a data acquisition unit  380 . Data acquisition unit  380  may be located at the surface, as shown in  FIG. 3 , or somewhere on housing  310 . 
     At the bottom of the housing  310 , there is located the second magnet assembly  350 , that has a similar structure as the first magnet assembly  330 . Magnet  352  may be sandwiched between pole pieces  353  and lower coil  354  encircles magnet  352 . A coil holder  356  supports lower coil  354  and a pair of wires  362  connects the lower coil to data acquisition unit  380 . Lower coil  354  is fixed relative to fill-in material  320  due to anchor  360 , which extends into the fill-in material. 
     First and second magnet assemblies  330  and  350  are connected to one another via rigid member  382 , which in one embodiment is a metal pipe. Rigid member  382  may be attached at its midpoint to anchor  384 , which can be a plate, flange or other structure for attaching rigid member to fill-in material  320 . In this way, the distance between the magnets of the two magnet assemblies is constant and does not change in time. Further, by fixing the rigid member  382  to the fill-in material, it is expected that the two magnets  332  and  352  would not move relative to each other. However, the two coils  334  and  354  are expected to move relative to each other as the seismic waves strain the fill-in material. 
     When in operation, seismic sensor  300  experiences the following actions. A pressure wave  390 , for example, from a rock interface  392  at a certain depth below the surface, is propagating upwards (along Y direction, which coincides with gravity) toward the surface  304 . As the wave  390  passes through seismic sensor  300 , there will be a change in the distance separating lower anchor  360  and upper anchor  340 . During the compression portion of the pressure wave  392 &#39;s arrival, a separation distance b 1 +b 2  between the two anchors will decrease, and during the rarefaction portion of the pressure wave  392 , this axial dimension will increase. Because upper and lower coils  334  and  354  are tied into the fill-in material  320 , their separation distance will change as the pressure wave passes. However, a distance a 1 +a 2  between magnets  332  and  352  will not change. This is so because bar  382  is rigid and has its endpoints isolated from the fill-in material. Only the midpoint of bar  382  is tied to the formation through anchor  384 . Thus, even if the bar moves up and down, the separation distance a 1 +a 2  will remain fixed (it is assumed that the bar and plate are stiff at the frequencies of interest, i.e., below 200 Hz). 
     When these movements take place, the magnets slightly move relative to the upper and lower coil, thus, inducing an EMF voltage in each coil. These voltages are transmitted by pairs of coils  342  and  362  to data acquisition unit  380 . Thus, data acquisition unit  380  receives a first voltage e 1 , measured across pair  362 , and this voltage is proportional to the relative velocity of coil  354  with respect to magnet  352 . This means that the output voltage e 1  is proportional to the velocity of anchor  360  relative to anchor  384 . Likewise, voltage e 2  is measured across pair  342 , which is connected to coil  334 , and this voltage is proportional to the relative velocity of coil  334  relative to magnet  332 . Alternatively, pairs  343  and  362  are interconnected in such a way to directly record voltage e 3 . This approach allows a higher sensitivity setting on the recorder to recover lower energy signals from greater depth. 
     If the magnets and coils are polarized at both ends of the seismic sensor, so that a downward motion of the coil relative to the magnet creates a positive voltage, that means that e 1 &gt;0 and e 2 &gt;0. By forming the difference voltage e 3 =e 1 −e 2  by interconnecting the pair of wires or in data acquisition unit  380 , it is possible to obtain a voltage that is proportional to the differential velocity between anchors  360  and  340 . In other words, with the configuration shown in  FIG. 3 , it is possible to measure the rate of change (or the time derivative) of the strain, in the vertical axial dimension, of the fill-in material (one objective of the seismic sensor is to determine the strain or strain rate in the formation in which the fill-in material is provided; this objective may be achieved by measuring the strain or strain rate of the fill-in material; however, it is possible to also achieve this objective by having the anchors bonded to the formation), as the pressure wave passes through it. Note that although the embodiments are discussed as the magnets are moving and the coils are fixed, the inventive concepts equally apply to a system having the magnets fixed and the coils moving relative to the magnets. For this reason, the term “movement of the magnets relative to the coils” means either the coils are fixed and the magnets are moving or the coils are moving and the magnets are fixed. 
     Due to the location of the two magnet assemblies, i.e., along the vertical axis Y, the seismic sensor  300  will have a directional response in terms of P-waves response (P-waves behave like plane waves far away from their source and thus, they extend or contract the medium in the direction of their propagation). This means that the seismic sensor  300  will tend to have a cosine response to a pressure wave arriving at angles away from vertical. This means that for a pressure wave arrival at 30° degrees from the gravity axis, the sensitivity of the seismic sensor will decrease to about 86.6%, and for a pressure wave arrival that is in the horizontal direction X (like the ground roll waves), the sensitivity of the seismic sensor (if the coils are matched) will approach zero, as desired. In other words, the seismic sensor  300  illustrated in  FIG. 3  would detect the strain changes in the fill-in material without recording the ground roll waves. While orienting the seismic sensor may be useful to boost sensitivity to P-waves in a preferred direction in one embodiment, it is also possible, in another embodiment, to orient the seismic sensor to reject S-waves that are arriving from the same direction as the P-waves. Thus, orienting the seismic sensor&#39;s central axis in line with the P-wave arrivals may also be helpful in rejecting S-waves coming from the same direction. 
     In another embodiment, at the time of manufacture, if it is found that coils  334  and  354  and magnets  332  and  352  are not well matched (e.g., they do not have the same velocity sensitivity), external components (for example, series and shunt resistors) can be used to improve the matching. 
     For a practical implementation of the seismic sensor  300 , the distance b 1 +b 2  might be about 1 m, but other dimensions are possible. In general, the greater the separation distance, the more sensitive the seismic sensor will become. 
     Seismic sensor  300  discussed above is one possible implementation of the inventive concept.  FIG. 5  shows another possible implementation of a seismic sensor  500  capable of measuring seismic waves while reducing the impact of ground roll. Seismic sensor  500  includes two separate units, an upper unit  528  that measures the axial dilation b 1  and a lower unit  548  that measures dilation b 2 . In this case, rigid member  382  in  FIG. 3  is split into two parts,  582 A and B, each one corresponding to one of the upper and lower units. Anchor  384  from  FIG. 3  is also split into two anchors  584 A and B. All other elements in the embodiment of  FIG. 5  are similar to those of  FIG. 3 , and for this reason, similar parts are not discussed herein. By choosing the proper interconnection of the coils  534  and  554 , it is possible to measure the overall dilation b 1 +b 2 . A distance d between anchors  584 A and B is can be adjusted depending on the field conditions, and it may be added to the overall dilation if necessary. 
     In another embodiment, the distance d may be made zero, which means that anchors  584 A and  584 B are attached to each other by fasteners. Thus, devices  528  and  548  may be manufactured separately. 
     In still another embodiment, as illustrated in  FIG. 6 , seismic sensor  600  has a single magnet assembly  630 , located at the upper or lower half of the sensor.  FIG. 6  shows an embodiment in which single magnet assembly  630  is located at the upper half of housing  610 . However, it is possible to have the single magnet assembly  630  located in the lower half of the housing. Bar  682  is directly connected with one end to anchor  660  while the other end is connected to magnet  632 . In this embodiment, seismic sensor  600  measures the relative velocity of upper anchor  640  relative to lower anchor  660 . Lower anchor  660  may be located anywhere inside housing  610 . However, in one embodiment, the lower anchor is located at one end of the housing. The relative velocity is represented by a voltage output e 3  that is present on wire pair  642 , which is connected to coil  634 . 
     In still another embodiment, as illustrated in  FIG. 7 , a seismic sensor  700  may have two magnet assemblies  730  and  750 , similar to the embodiment of  FIG. 3 , but the magnet assemblies are located near the center  790  of the axial length of the housing. Thus, anchor plates  740  and  760  may be joined to each other near the midpoint of the housing and anchor plate  384  is replaced by two plates  784 A and B, which are now located at the top and bottom, respectively, of housing  710 . Those skilled in the art would understand that these elements may be placed at other locations inside the housing. 
     Although the above embodiments discussed placing the seismic device in a vertical borehole, in an embodiment, the seismic device could be installed in a slanted borehole, to be more sensitive to body waves arriving from a direction other than vertical or to reject certain arrivals that are undesirable, e.g., S-waves. 
     The above embodiments discussed a seismic device having one or more magnetic assemblies for measuring a voltage indicative of a time derivative of the medium&#39;s strain. However, as discussed now, it is possible to replace the magnetic assemblies with other type of sensors. In this respect,  FIG. 8  shows a seismic sensor having at least one piezoelectric assembly  830  located at one end of housing  810 . Note that most reference numbers shown in this figure point to similar components as the corresponding reference numbers in  FIG. 3 , except for piezoelectric assembly  830 . 
     Piezoelectric assembly  830  is shown in more detail in  FIG. 9 , and it includes a piezoelectric element  890  having its ends  891  fixed to housing  810  or another local housing  811 . If the ends  891  of the piezoelectric element  890  are attached to local housing  811 , for example, with a bonding material  897 , a central part of the material  890  is attached to rod  882  via connecting device  895 , for example, a hub or a bonding material. Wires  842  are attached to the two opposite faces of piezoelectric element  890  for measuring the voltage induced by its deformation. 
     The piezoelectric element could be a PZT disc that has been polarized and has electrodes (for example silver or nickel deposition) on the upper and lower parts with wires attached, which are brought out to a charge amplifier  893 , that can be located in close proximity at/or near the surface, and the data acquisition unit  880 . If there is relative motion between the central bar  882  and the anchor  840  near where the piezoelectric element is positioned, then an electric charge will be generated. The rate of change in the charge should be proportional to the strain rate. 
     In still another embodiment, it is possible to measure the strain and not its derivative as now discussed with regard to  FIG. 10 .  FIG. 10  shows a sensor device  1000  having a transducer assembly  1030  instead of magnetic assembly  330 . The configuration of the sensor device is similar to that shown in  FIG. 8 . Rod  1082  is connected to a core  1094  of a Linear Variable Differential Transformer (LVDT)  1095 . LVDT  1095  measure the strain in the ambient formation by measuring the change in distance between the center rod  1082  that is attached to a lower anchor plate (shown in  FIG. 8 ) and an upper anchor plate  1040 . In this case, an oscillator  1102  that generates an AC signal could be used to drive the primary LVDT winding  1104  as illustrated in  FIGS. 11A-B . The secondary winding  1106  is comprised of two coils that are connected back to back, and they will have a net AC voltage Vout whose amplitude is directly proportional to core&#39;s  1094  position and whose polarity relative to the AC excitation signal will change depending upon whether the core is above or below the center/null position.  FIG. 11A  shows the LVDT core  1094  centered so that magnetic field  1120  generated by the primary winding  1104  is evenly coupled to both secondary windings  1106  to produce a net zero output. In  FIG. 11B , the LVDT core  1094  is shown at the upper end of its travels so that the upper secondary coil of winding  1106  is well coupled to the magnetic field  1120  created by the primary winding  1104  while the lower secondary coil is not well coupled to create a net voltage output from the combined secondary windings. An LVDT demodulator  1108  could be used to convert the signal Vout to a seismic signal. Sensors capacitively coupled rather than inductively coupled can be configured to accomplish the same result. 
     Other options would include an optoelectric sensor that is sensitive to a change in distance or rate of change in distance between the center rod and the upper anchor. Instead of the optoelectric sensor, the sensor could be ultrasonic, an eddy current transducer, or a Hall effect type sensor (the hall effect sensor is used instead of a coil to detect the magnet&#39;s motion and/or position). 
     The above embodiments illustrated a single-component seismic sensor, i.e., a seismic sensor that measures a single time derivative of the strain of fill-in material in which the seismic sensor is placed. However, in one embodiment, as illustrated in  FIG. 12 , a multi-component seismic device  1200  could be constructed by arranging two or more single component sensors  1202 ,  1204  and  1206  along orthogonal axes X, Y and Z (axis Z is entering into the page in the figure). Components  1202  to  1206  may be any of the seismic sensors previously discussed. For example, the seismic device as shown in  FIG. 3  is aligned with the Z axis, while another device is aligned with the X-axis and still another device is aligned with the Y-axis. While  FIG. 12  shows each of the three single seismic sensors as having its own housing, it is possible that the three seismic sensors share a single housing. In another embodiment, the multi-component sensor could use a Galperin arrangement, i.e., an arrangement in which three orthogonal elements each make a 54 degree-35 minute angle with respect to the vertical axis. 
     According to an embodiment illustrated in  FIG. 13 , there is a method for determining a time derivative of a strain in a fill-in material. The method includes a step  1300  of placing a seismic device in a borehole, a step  1302  of filling the well with the fill-in material so that the seismic device is surrounded by the fill-in material, a step  1304  of generating a seismic wave with a seismic source, and a step  1306  of measuring a strain or its time derivative in the fill-in material with the seismic device. The strain in the fill-in material is a result of the seismic wave passing through the fill-in material. 
     The disclosed embodiments provide a buried seismic sensor that is less sensitive to ground roll. It should be understood that this description is not intended to limit the embodiments. On the contrary, the embodiments are intended to cover alternatives, modifications, and equivalents, which are included in the spirit and scope of the embodiments as defined by the appended claims. Further, in the detailed description of the embodiments, numerous specific details are set forth to provide a comprehensive understanding of the claimed embodiments. However, one skilled in the art would understand that various embodiments may be practiced without such specific details. For example, the above described embodiments generally describe various types of seismic receivers which can be used for various seismic data acquisition applications. They can be used with any type of seismic source or application including, for example, fracture monitoring, passive seismic monitoring or other oil field activities. For these cases the seismic waves can be generated by any type of mechanism, e.g., natural events or man-made events, such as a drill bit, or fluid injection/fracking. 
     Although the features and elements of the embodiments are described in the embodiments in particular combinations, each feature or element can be used alone, without the other features and elements of the embodiments, or in various combinations with or without other features and elements disclosed herein. 
     This written description uses examples of the subject matter disclosed to enable any person skilled in the art to practice the same, including making and using any devices or systems and performing any incorporated methods. The patentable scope of the subject matter is defined by the claims, and may include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims. 
     The above-described embodiments are intended to be illustrative in all respects, rather than restrictive, of the embodiments. Thus the embodiments are capable of many variations in detailed implementation that can be derived from the description contained herein by a person skilled in the art. No element, act, or instruction used in the description of the present application should be construed as critical or essential to the embodiments unless explicitly described as such. Also, as used herein, the article “a” is intended to include one or more items.