Abstract:
In some embodiments, a method includes receiving a data signal from a sensor that is positioned within a well bore, during a hydraulic fracturing operation. The method further comprising detecting a microseismic event, that is caused by the hydraulic fracturing operation, wherein the detecting comprises performing a noise canceling operation on the data signal.

Description:
TECHNICAL FIELD 
       [0001]    Some embodiments relate to monitoring of fractures during hydraulic fracturing of a well bore. More particularly, some embodiments relate to monitoring of such fractures within the well bore where hydraulic fracturing is being performed. 
       BACKGROUND 
       [0002]    A number of techniques have been developed to increase the production of hydrocarbons from well bores drilled in the Earth. One technique includes hydraulic fracturing. A hydraulic fracturing operation fractures a portion of the subsurface formation by injecting a fluid into the well bore that creates or extends one or more fractures therein. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0003]    Embodiments of the invention may be best understood by referring to the following description and accompanying drawings which illustrate such embodiments. In the drawings: 
           [0004]      FIG. 1  illustrates a system for hydraulic fracturing operations, according to some embodiments of the invention. 
           [0005]      FIG. 2  illustrates a block diagram of a part of a system for filtering a signal captured during hydraulic fracturing operations, according to some embodiments of the invention. 
           [0006]      FIG. 3  illustrates an adaptive filtering for processing the signal acquired during hydraulic fracturing operations, according to some embodiments of the invention. 
           [0007]      FIG. 4  illustrates an adaptive filter, according to some embodiments of the invention. 
           [0008]      FIG. 5  illustrates an adaptive filtering for processing the signal acquired during hydraulic fracturing operations, according to some other embodiments of the invention. 
           [0009]      FIG. 6  illustrates an adaptive filtering for processing the signal acquired during hydraulic fracturing operations, according to some other embodiments of the invention. 
       
    
    
     DETAILED DESCRIPTION 
       [0010]    Methods, apparatus and systems for hydraulic fracturing monitoring in the treatment well are described. In the following description, numerous specific details are set forth. However, it is understood that embodiments of the invention may be practiced without these specific details. In other instances, well-known circuits, structures and techniques have not been shown in detail in order not to obscure the understanding of this description. 
       System Description 
       [0011]      FIG. 1  illustrates a system for hydraulic fracturing operations, according to some embodiments of the invention. A wellbore  10  penetrates a subterranean formation for the purpose of recovering hydrocarbon fluids from the formation. A tool  12  is lowered into the wellbore  10  to a depth that is below a fracture treatment zone  100  by a string  14 , in the form of wireline, coiled tubing, wireline inside coil tubing, slickline, tubing, wired pipe, armed coaxed cable or the like, which is connected to the upper end of the tool  12 . In some embodiments, the coiled tubing may be a multiconductor coil. A packer  102  may be coupled to the string  14  and is lowered into the wellbore  10 . In some embodiments, the packer  102  may be retrievable, expandable or inflatable. In some embodiments, the packer  102  may be permanent. The packer  102  is positioned above the tool  12  and below the fracture treatment zone  100 . In some embodiments, the packer  102  is inflatable. Accordingly, a unit at the surface may inflate the packer  102  through the coiled tubing attached thereto. In some embodiments, the packer  102  may be set on a trip for placing the tool  12  downhole. Alternatively, the packer  102  may be set on a different trip relative to the placing of the tool  12  downhole. 
         [0012]    The tool  12  may comprise one or more geophones for microseismic detection and a receiver/transmitter module to communicate with equipment at the surface of the Earth. The string  14  extends from the surface of the Earth to a position in the wellbore  10 . In some embodiments, the string  14  extends from a rig (not shown) that is located on the ground surface and over the wellbore  10 . The rig is conventional and, as such, includes, inter alia, support structure, a motor driven winch, and other associated equipment for receiving and supporting the tool  12  and lowering it to a predetermined depth in the wellbore  10  by unwinding the string  14  from a reel, or the like, provided on the rig. Also, stimulation, or fracturing, fluid can be introduced from the surface, through the wellbore  10 , and into the fracture treatment zone  100 . 
         [0013]    At least a portion of the wellbore  10  can be lined with a casing  20  which is cemented in the wellbore  10  and which can be perforated as necessary, consistent with typical downhole operations and with the operations described herein. Perforations may be provided though the casing  20  and the cement to permit access to the fracture treatment zone  100 . In some embodiments, a string of production tubing (not shown) having a diameter greater than that of the tool  12 , and less than that of the casing  20 , may be installed in the wellbore  10  and to extend from the ground surface to a predetermined depth in the casing  20 . 
         [0014]    During a hydraulic fracturing operation, a fracturing fluid carrying a proppant is introduced into the wellbore  10 . By monitoring the changes in the data sensed and displayed in real time, personnel would then be able to quickly and efficiently adjust downhole conditions such as proppant concentration, pump rates, fluid properties, net pressures, and other variables, to control the safety and efficiency of the fracturing operation, and to obtain optimum fracture design. The treatment of the formation generates the hydraulically induced fractures. The geophones in the tool  12  detect the microseismic events that result from the hydraulic induced fracturing. After the treatment is complete, in some embodiments, the packer  102  is then deflated. The packer  102  and the tool  12  are then retrieved. 
         [0015]    While described such that the tool  12  is below the fracturing operation, embodiments are not so limited. In some embodiments, the tool may be positioned adjacent to or above the fracturing operation. In some embodiments, multiple tools may be used. For example, a first tool may be positioned above, and a second tool is positioned below the fracturing operation. Thus, one to any number of geophones may be used to detect the microseismic events. In some embodiments, a packer is not used. In some embodiments, the packer may be positioned at different zones in the wellbore. Accordingly, sequential fracturing operations may be performed at different locations in the wellbore. In some embodiments, geophones may be mounted at one or more locations on a wire that is lowered into the wellbore. In some embodiments, the geophones may be mounted at different locations in the wellbore without a wire (such as on the casing  20 ). 
       Noise Cancellation and Dampening 
       [0016]    The signals acquired by the geophones in the tool  12  may be processed to detect the microseismic events therein that are caused by the hydraulic fracturing operation. The hydraulic fracturing operation may produce noise that may be removed during the processing of the acquired signal to detect the microseismic events. Such noise may be caused by the pumps at the surface and the fluid moving through the wellbore and fracture treatment zone, etc. In some embodiments, one to a number of different noise cancellation operations is performed to reduce the surrounding noise for detection of the microseismic events resulting from the hydraulic fracturing operation. The noise cancellation operations may be performed in real time or offline. Such operations may be performed in the tool  12  or by equipment at the surface. The noise cancellation operations may be performed by hardware, software, firmware or a combination thereof. 
         [0017]    In some embodiments, the signal acquired by the geophones is processed using various signal processing analog and/or digital filtering operations. Such operations may remove the unwanted noise from the signal that is created by the hydraulic fluid being pumped down the well bore and out the perforations of the casing and into the formations. Examples of the different filtering operations that may be used include cross correlation functions, band pass, etc. In some embodiments, an adaptive noise cancellation operation is performed. In some embodiments, geophones, accelerometers and other sensors may be positioned near potential noise sources. These noise signals acquired may be used as input into the noise cancellation operation. 
         [0018]      FIG. 2  illustrates a block diagram of a part of a system for filtering a signal captured during hydraulic fracturing operations, according to some embodiments of the invention. A filtering device  42  receives the signals  40 ,  38  output by a geophone  26  and an accelerometer  36 , respectively, and produces an output signal  44  which is input to a signal analysis unit  46 . 
         [0019]    Initially, the signals  38 ,  40  are preferably input to an analog-to-digital converter  58 . This step may also include signal conditioning, e.g., placing the signals  38 ,  40  in a usable form for the remainder of the signal filtering process. An output  60  of the converter  58  is, thus, in digital form and ready for further processing. 
         [0020]    The converter output  60  (which includes digitized and conditioned versions of the signals  38 ,  40 ) is then input to a filter  62 . The filter  62  performs the function of reducing or eliminating the contribution of the noise signal to the contaminated signal  40 . An output  64  of the filter  62 , thus, is more closely representative of the microseismic events due to the hydraulic fracturing rather than due to noise sources (e.g., the pump noise, fluid flow noise, etc.). 
         [0021]    The filter output  64  may be transmitted directly to the signal analysis unit  46  in digital form, or it may be input to another converter  66  prior to transmission to the signal analysis unit. As depicted in  FIG. 2 , the converter  66  is a digital-to-analog converter since, in this particular example, the signal analysis unit  46  is configured to receive analog signals. The converter  66  may also include signal conditioning to place the output  44  in a form usable by the signal analysis unit  46 . 
         [0022]      FIG. 3  illustrates an adaptive filtering for processing the signal acquired during hydraulic fracturing operations, according to some embodiments of the invention.  FIG. 3  illustrates a schematic diagram of the filtering device  42 . 
         [0023]    As depicted in  FIG. 3 , the letter “s” is used to indicate the desired signal that includes the microseismic events, which is acquired during the hydraulic fracturing operations, and which may be contaminated by its combination with the noise signal. A noise source  34  is depicted in  FIG. 3  as being the source of noise (indicated by the letter “v”). This noise “v” is altered in unknown ways by environmental factors  68 , such as the flow of the fluid, the type of fluid, the speed of the pumps, size of perforations, etc., and results in a variation in the noise as indicated by an output  40 . This variation due to the noise source  34  is the noise signal, which is combined with the desired signal “s” to produce the noise-contaminated signal (indicated by the letter “t”). The noise-contaminated signal “t” is detected by one of the geophones  26 , which produces the noise-contaminated signal  40 . 
         [0024]    The noise “v” may be detected by an accelerometer  36 , which produces the signal  38  indicative or characteristic of the noise “v”. Both the noise-contaminated signal  40  and the signal  38  characteristic of the noise v are input to the filtering device  42 . The filtering device  42  includes a filter  62 , which is preferably of the type known to those skilled in the art as an adaptive filter. 
         [0025]    The filter  62  receives the signal  38  and produces an output signal indicated in  FIG. 2  by the letter “a”. The output signal “a” is summed with (actually, subtracted from) the noise-contaminated signal  40  to produce an error output indicated in  FIG. 2  by the letter “e”. This error output “e” is input to the adaptive filter  62 , which adapts to minimize the error. 
         [0026]      FIG. 4  illustrates an adaptive filter, according to some embodiments of the invention. An example of an adaptive filter  68  which may be used for the filter  62  in the filtering device  42  is representatively illustrated. The signal  38  characteristic of the noise “v” is indicated in  FIG. 4  by the function v(k), where k is a time sample index. A number n of tapped-delay inputs D are individually weighted (w 1  through w n ) and summed in a summer  70  along with a parameter b. One or more additional optional linear function  72  may be applied to the output of the summer  70  to produce the output a(k). 
         [0027]    Thus, the output a(k) of the filter  68  is given by the following equation: 
         [0000]        a ( k )= w   1   v ( k )+ w   2   v ( k− 1)+ . . . + w   n   v ( k−n )+ b    
         [0028]    The filter parameters w and b may be updated in real-time in the direction of gradient descent, i.e.: 
         [0000]        w ( k+ 1)= w ( k )+η e ( k ) v ™( k ) 
         [0000]        b ( k+ 1)= b ( k )+η e ( k ), 
         [0029]    where  w ( k )=[ w   1 ( k )  w   2 ( k ) . . .  w   n ( k )],  v   T ( k )=[ v ( k ) . . .  v ( k− 1)  v ( k−n )], η is the learning rate, and e(k) is the “error” at the sample time index k. 
         [0030]    Each time an error value is obtained, a new sample is loaded, and the filter parameters are updated again. The learning rate η and number n of tapped-delay lines D are preferably adjustable by the user, for example, using some type of user interface to obtain the “cleanest” (noise-free) output signal  44 . 
         [0031]    It is to be clearly understood that any type of adaptive filter could be used for the filter  62 . For example, an adaptive IIR filter structure, or a more complex nonlinear filter, such as a neural network, could be used. Any of the many numerical optimization algorithms, such as the extended Kalman filter, recursive Gauss-Newton, recursive least-squares, Levenberg-Mardquart, etc. can be used to train or adjust the filter  62 . 
         [0032]      FIG. 5  illustrates an adaptive filtering for processing the signal acquired during hydraulic fracturing operations, according to some other embodiments of the invention.  FIG. 5  illustrates a schematic diagram of the filtering device  42 . 
         [0033]    As shown, multiple noise sources  34 ,  74 ,  76  contribute to the noise. For example, the noise sources  34 ,  74 ,  76  may be the hydraulic pump at the surface for pumping the fluid downhole, the fluid flow, etc. 
         [0034]    Each of the signals  38 ,  80 ,  84  is input to the adaptive filter  62  using respective tapped-delay lines  86 ,  88 ,  90 . The output “a” of the adaptive filter  62  is summed with the contaminated force sensor signal  40 , and the resulting error “e” is also input to the filter using a tapped-delay line  92  to update the filter parameters “w” and “b”. Parameters of the filter  62 , such as weights applied to each of the individual tapped-delay inputs, may be updated with each sample of values in the signals  40 ,  38 ,  80 ,  84 . 
         [0035]    One or more additional filters, such as the linear filter  72  shown in  FIG. 4 , may also be used in this alternate construction of the filtering device  42 . Note that the filter  62  may be a linear adaptive filter, or a nonlinear adaptive filter, such as a neural network. 
         [0036]      FIG. 6  illustrates an adaptive filtering for processing the signal acquired during hydraulic fracturing operations, according to some other embodiments of the invention.  FIG. 6  illustrates a schematic diagram of the filtering device  42 . As shown, only one noise source  94  is used. A sensor  96  attached to, or part of, the noise source  94  produces a signal  98  indicative or characteristic of the noise generated by the noise source. 
         [0037]    The signal  98  is input to the adaptive filter  62  via a tapped-delay line  100 . The filter  62  generates an output a, which is summed with the noise-contaminated signal  40 . The resulting error “e” is input to the adaptive filter  62  via a tapped-delay line  102 . 
         [0038]    One or more additional filters, such as the linear filter  72  shown in  FIG. 4 , may also be used in this alternate construction of the filtering device  42 . Note that the filter  62  may be a linear adaptive filter, or a nonlinear adaptive filter, such as a neural network. Additional description of the noise filtering is set forth in U.S. Pat. No. 7,053,787 to Schultz, et al., (assigned to Halliburton Energy Services, Inc.) issued May 30, 2006, which is hereby incorporated by reference. 
         [0039]    In some embodiments, active cancellation may be used to cancel the noise. For example, acoustic waves may be generated that may cancel the noise generated by the pumps at the surface by using piezos or other similar devices. In some embodiments, noise captured at the surface may be used to generate a similar pattern in the well bore that may cancel the effect of the surface noise. The direct communication link between the surface and downhole may allow a quick generation of a “cancellation signal” in the well bore. 
         [0040]    In some embodiments, the pumping at the surface may be performed in a pulse pattern. Accordingly, during moments while the pump is not pumping, features of the signal may be obtained to detect the microseismic events. A model may fill the moments when the pumping is in progress. The profile of the flow of the output ports of the tool may be reviewed to reduce the noise profile. Such profile may be reviewed to generate some specific patterns that may assist in the detection of the microseismic events. 
         [0041]    In some embodiments, various noise dampening techniques may be used alone or in combination with the noise cancellation operations. For example, various mechanical dampening methods may be used to remove the unwanted noise. The mechanical dampening could include using a specially designed packer above the geophones and below the perforations to isolate the fluid flow and to dampen the vibrations. A heavy rubber material similar to the “flubber” used on the Bi-modal Acoustic Tool may be used. See U.S. Pat. Nos. 5,886,303 to Rodney (Assignee: Dresser Industries, Inc.) issued Mar. 23, 1999; 6,102,152 to Masino, et al. (Assignee: Halliburton Energy Services) issued Aug. 15, 2000; 6,151,554 to Rodney (Assignee: Dresser Industries, Inc.) issued Nov. 21, 2000, all hereby incorporated herein by reference. In some embodiments, one or more dampening packers may be positioned below the isolation packer. 
         [0042]    Various cancellation and damping techniques have been described. Such techniques may be performed in any combination. In particular, one, some or all of the techniques may be performed together. 
       General 
       [0043]    In the description, numerous specific details such as logic implementations, opcodes, means to specify operands, resource partitioning/sharing/duplication implementations, types and interrelationships of system components, and logic partitioning/integration choices are set forth in order to provide a more thorough understanding of the present invention. It will be appreciated, however, by one skilled in the art that embodiments of the invention may be practiced without such specific details. In other instances, control structures, gate level circuits and full software instruction sequences have not been shown in detail in order not to obscure the embodiments of the invention. Those of ordinary skill in the art, with the included descriptions will be able to implement appropriate functionality without undue experimentation. 
         [0044]    References in the specification to “one embodiment”, “an embodiment”, “an example embodiment”, etc., indicate that the embodiment described may include a particular feature, structure, or characteristic, but every embodiment may not necessarily include the particular feature, structure, or characteristic. Moreover, such phrases are not necessarily referring to the same embodiment. Further, when a particular feature, structure, or characteristic is described in connection with an embodiment, it is submitted that it is within the knowledge of one skilled in the art to affect such feature, structure, or characteristic in connection with other embodiments whether or not explicitly described. 
         [0045]    Some or all of the operations described herein may be performed by hardware, firmware, software or a combination thereof. Upon reading and comprehending the content of this disclosure, one of ordinary skill in the art will understand the manner in which a software program can be launched from a machine-readable medium in a computer-based system to execute the functions defined in the software program. One of ordinary skill in the art will further understand the various programming languages that may be employed to create one or more software programs designed to implement and perform the methods disclosed herein. The programs may be structured in an object-orientated format using an object-oriented language such as Java or C++. Alternatively, the programs can be structured in a procedure-orientated format using a procedural language, such as assembly or C. The software components may communicate using any of a number of mechanisms well-known to those skilled in the art, such as application program interfaces or inter-process communication techniques, including remote procedure calls. The teachings of various embodiments are not limited to any particular programming language or environment. 
         [0046]    In view of the wide variety of permutations to the embodiments described herein, this detailed description is intended to be illustrative only, and should not be taken as limiting the scope of the invention. What is claimed as the invention, therefore, is all such modifications as may come within the scope and spirit of the following claims and equivalents thereto. Therefore, the specification and drawings are to be regarded in an illustrative rather than a restrictive sense.