Patent Publication Number: US-2015083405-A1

Title: Method of conducting diagnostics on a subterranean formation

Description:
RELATED CASES 
     This application claims the benefit of U.S. Provisional Application No. 61/882,139, filed on Sep. 25, 2013, which is incorporated herein by reference. 
    
    
     FIELD OF THE INVENTION 
     The invention relates to a method of conducting diagnostics on a subterranean formation. 
     BACKGROUND 
     Hydraulic fracturing of reservoirs is a technology optimizing the value of subterranean hydrocarbon-bearing formations and, in particular, of unconventional gas and liquid rich shale deposits. Due to the tight nature of formations containing such deposits, standard techniques for reservoir characterization and hydraulic fracture design are often inapplicable or present interpretation challenges. Understanding leak-off process is a key component of characterization and design. A standard practice of leak-off estimation involves conducting a minifrac or leak-off test. Due to very low permeability of the unconventional gas and liquid rich shale formations this test generally provides poor results. Another way to estimate the leak-off is to use analytical approach which requires knowledge of some parameters of the formation such as permeability and porosity. However, these parameters can be very hard to estimate in tight formations. 
     SUMMARY OF THE INVENTION 
     In accordance with one aspect of the present disclosure, a method includes providing a first sensor in an injection well penetrating a subterranean formation. The method also includes providing a second sensor in an observation well penetrating the subterranean formation. The method further includes increasing pressure within the injection well until a fracture extends from an initiation location in the injection well through a portion of the subterranean formation to an intersection location in the observation well, wherein increasing pressure within the injection well comprises introducing fluid into the injection well. The method includes obtaining a measurement indicative of fracture initiation from the first sensor. Additionally, the method includes determining a height of the fracture at the injection well. The method also includes obtaining a measurement indicative of fracture intersection from the second sensor. The method includes determining a volume of fluid introduced between the fracture initiation and the fracture intersection. Additionally, the method includes determining a distance between the initiation location and the intersection location. The method also includes determining a time lapse between the fracture initiation and the fracture intersection. Additionally, the method includes using the determined values, calculating a hydraulic fracturing characteristic. 
    
    
     
       BRIEF DESCRIPTION OF THE FIGURES 
         FIG. 1  illustrates a schematic of an injection well and an observation well with a fracture extending therebetween in accordance with one aspect of the present disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     The present disclosure provides methods for field testing and deriving hydraulic fracturing parameters. Generally, a combination of distributed temperature and acoustic sensors are installed in a vertical and deviated well respectively to measure fracture height, time required for the fracture to grow to a length, and fluid leak-off rate. The estimated parameters may also be employed in history matching to decrease the uncertainty in characterizing the stress field, fracture toughness of the formation, and other related properties. 
     Referring now to  FIG. 1 , an injection well  10  and an observation well  12  may be provided. The injection well  10  may be a hydraulically fractured well. One or both of the injection well  10  and the observation well  12  may penetrate a subterranean formation  14  of interest. For example, the subterranean formation  14  may contain hydrocarbon or other natural resources. The injection well  10  and the observation well  12  may originate at a surface  15  at a single pad (not shown). However, as illustrated, the injection well  10  originates at the surface  15  at an injection pad  16  and the observation well  12  originates at the surface  15  at an observation pad  18 . A method of evaluating a formation may include placing or otherwise providing a sensor  20  in the injection well  10  at a location where the sensor  20  can sense a parameter indicative of fracture initiation from an initiation location  24  in the injection well  10 . As illustrated, the initiation location  24  is a perforation in casing, isolated by two packers  23 . The sensor  20  may be a distributed temperature sensor (DTS), a pressure gauge, multiple pressure gauges, etc. For example a fiber optic DTS may be attached to the wellbore casing and provide measurements of temperature decrease (or increase) in response to the injection of cool (hot) fluid. In some embodiments, including the embodiment illustrated, the sensor  20  may be placed in a substantially vertical portion  25  of the injection well  10 . In such embodiments, the initiation location  24  may be in the substantially vertical portion  25  of the injection well  10 . 
     The method may also include placing or otherwise providing another sensor  26  in the observation well  12  at a location where the sensor  26  can sense a parameter indicative of fracture intersection at an intersection location  30  in the observation well  12 . The sensor  26  may be a distributed acoustic sensor (DAS), a DTS, a DAS/DTS combination, or any other instrumentation in the observation well  12 . A fiber optic DAS may be attached to the wellbore casing and measure the deformation induced by fracturing. A DAS and DTS may be simultaneously used in one wellbore. Alternatively, pressure gauges may be present in the observation well or in both injection and observation wells. In some embodiments, including the embodiment illustrated, the sensor  26  may be placed in a deviated portion  31  of the observation well  12 . In such embodiments, the intersection location  30  may be in the deviated portion  31  of the observation well  12 . 
     The injection well  10  and the deviated portion  31  of the observation well  12  may be positioned along the direction of maximum horizontal stress σ H . Once the sensor  20  has been provided in the injection well  10  and the sensor  26  has been provided in the observation well  12 , fluid may be introduced into the injection well  10  at the surface  15 . The pressure within the injection well may be gradually increased by pressurizing the fluid until a fracture  34  begins to form. The fracture  34  may extend from the initiation location  24  in the injection well  10 , through a portion of the subterranean formation  14 , to the intersection location  30  in the observation well  12 . While it is likely that the fracture  34  would continue beyond the intersection location  30 , the present disclosure notes that the intersection location  30  is of particular interest. 
     The initiation of the fracture  34  may provide a signal that can be detected by the sensor  20 . For example, breaking of the subterranean formation  14  may be registered by a pressure change, a thermal change, or some other change measurable by the sensor  20 . Thus, it may be possible to obtain a measurement indicative of fracture initiation from the sensor  20 . Such measurement may include an indication of the sensed value (e.g., a temperature measurement, a pressure measurement, deformation measurement, etc.) and indication of a time (“initiation time” or t 0 =0) at which the value was sensed. Such measurement(s) may be saved for later reference and use. In order to sense a change in the measurement of the sensor  20 , a baseline measurement may be obtained from the sensor  20  prior to any measurement associated with formation of the fracture  34 . Thus, determination of the time of initiation may involve comparing the baseline measurement with one or more subsequent measurements until a sufficient change characteristic of fracture initiation is detected. Thus, determining the time at which that change is detected provides a determination of the time of initiation. That change may reach a threshold temperature, pressure, or other value, depending on whether the sensor  20  is configured to detect a temperature change (when the baseline and subsequent measurements are temperature measurements), a pressure change (when the baseline and subsequent measurements are pressure measurements), or some other type of change The interpreted fracture initiation time can be further compared with and supported by the fracture initiation interpreted from the treating pressure record. 
     The height  36  of the fracture  34  may be determined at the injection well  10 . Specifically, the height  36  of the fracture  34  may be determined at the initiation location  24  via radioactive tracers, temperature logs, or any other instrumentation in the injection well  10 . In some embodiments, determining the height  36  of the fracture  34  may include obtaining an additional measurement from the sensor  20 . For example, if the sensor  20  is configured to provide temperature measurements, changes in temperature along the length of the sensor  20  may provide information about the height of the fracture  34 . Thus, determining the height  36  of the fracture may involve comparison of temperature measurements of the sensor  20  over time. 
     As injection proceeds with closely monitored and recorded injection volumes, the fracture  34  propagates through the subterranean formation  14 , until the fracture  34  intersects the observation well  12  at the intersection location  30 . The intersection of the fracture  34  with the observation well  12  may provide a signal that can be detected by the sensor  24 . For example, arrival of the fracture  34  at the observation well  12  may be registered by an acoustic change or some other change measurable by the sensor  26 . Such measurement may include an indication of the sensed value (e.g., an acoustic measurement, a temperature measurement, or a combination thereof) and an indication of a time (“intersection time” or t) at which the value was sensed. Such measurement(s) may be saved for later reference and use. In order to sense a change in the measurement of the sensor  26 , a baseline measurement may be obtained from the sensor  26  prior to any measurement associated with intersection of the fracture  34  with the observation well  12 . Thus, determination of the time of intersection may involve comparing the baseline measurement with one or more subsequent measurements until a sufficient change is detected. Thus, determining the time at which that change is detected provides a determination of the time of intersection. That change may reach a threshold acoustic or other value, depending on whether the sensor  26  is configured to detect an acoustic change (when the baseline and subsequent measurements are acoustic measurements or some other type of change). 
     The same process may optionally be repeated for additional observation wells (not shown) with use of additional sensors (not shown). In such instance, such additional measurement(s) may also be saved for later reference and use in a similar manner as that described with respect to the illustrated observation well  12 . 
     The initiation time and the intersection time may be used to determine a volume of fluid introduced between the fracture initiation and the fracture intersection. For example, the initiation time may be subtracted from the intersection time and a volumetric flow rate may be multiplied by the time lapsed. Alternatively, the initiation time might be set to zero, with a timer starting to measure time at the initiation time and stop measuring at the intersection time. Again, the time lapse may be multiplied by a steady volumetric flow rate. Alternatively, the volume of fluid introduced between the fracture initiation and the fracture intersection may be determined by other methods, including measuring, monitoring, recording, etc. 
     In addition to knowing the volume of fluid introduced and the height  36  of the fracture, it may be useful to determine a fracture length  38  or distance between the initiation location  24  and the intersection location  30 . The fracture length  38  may actually approximate a half-length of the fracture  34 . Thus, the length  38  may not include portions of the fracture  34  extending from the injection well  10  in a direction away from the observation well  12 . Likewise, the length  38  may exclude portions of the fracture  34  extending beyond the observation well  12 . Determining the fracture length  38  may be as straightforward as obtaining and comparing location measurements from the sensor  20  and the sensor  26 . Alternatively, fracture length can be estimated using microseismic monitoring. However, these measurements would likely be substantially less accurate and more uncertain. 
     In another embodiment (not shown), the injection well  10  may have a deviated portion and the initiation location  24  may be in the deviated portion of the injection well  10 . In such embodiments, the sensors  20 ,  26  may register the initiation time and intersection time and the sensors  20 ,  26  and/or additional sensors may further use microseismic data or other techniques allowing for an estimation of the height  36  of the fracture  34 . The same process may optionally be repeated for additional observation wells (not shown) with use of additional sensors (not shown). In such instance, such additional measurement(s) may be obtained in a similar manner and used to estimate fluid distribution between the fractures from DAS or other data. 
     Once the length  38 , height  36 , and volume of fluid introduced are known, a hydraulic fracturing characteristic may be calculated. For example, a leak-off volume, a leak-off coefficient, and/or permeability may be calculated. Some such calculations may involve additional determinations such as fluid pressure in the fracture, reservoir pressure, viscosity of the fluid, and fluid compressibility. Other characteristics, such as Young&#39;s modulus, Poisson ratio, complete elliptical integral of the second kind, and fracture net pressure may be determined and used in the methods described herein. 
     Based on relations of elasticity, leak off volume V loff  for a long rectangular fracture (L&gt;&gt;h) is 
     
       
         
           
             
               V 
               loff 
             
             = 
             
               
                 
                   V 
                   inj 
                 
                 - 
                 
                   V 
                   f 
                 
               
               = 
               
                 
                   
                     ∫ 
                     0 
                     t 
                   
                    
                   
                     Q 
                      
                     
                        
                       t 
                     
                   
                 
                 - 
                 
                   
                     
                       
                         π 
                         2 
                       
                       4 
                     
                     · 
                     
                       
                         1 
                         - 
                         v 
                       
                       E 
                     
                     · 
                     
                       
                         Lh 
                         2 
                       
                       
                         I 
                          
                         
                           ( 
                           m 
                           ) 
                         
                       
                     
                   
                    
                   Δ 
                    
                   
                       
                   
                    
                   p 
                 
               
             
           
         
       
     
     where V inj  is the injected fluid volume, V f  is the fracture volume at time t, Q is the volumetric injection rate, t is the time of sensor  26  registering intersection of the fracture  34  with the observation well  12 , h is the fracture height  36  (measured by sensor  30  in the injection well  10 ), L is the fracture half-length  38  (equal to the distance between the wells), E is the Young&#39;s modulus ν is the Poisson Ratio, I(m) is the complete elliptical integral of the second kind, Δp is the fracture net pressure, and 
     
       
         
           
             m 
             = 
             
               
                 
                   ( 
                   
                     h 
                     
                       2 
                        
                       L 
                     
                   
                   ) 
                 
                 2 
               
               . 
             
           
         
       
     
     Leak-off coefficient is calculated as 
     
       
         
           
             
               C 
               L 
             
             = 
             
               
                 3 
                 4 
               
                
               
                 
                   V 
                   L 
                 
                 
                   L 
                    
                   
                     t 
                   
                 
               
             
           
         
       
     
     Accounting for the connection between the leak-off and flow properties of the subterranean formation  14  the following constant can be estimated as well 
     
       
         
           
             
               k 
                
               
                   
               
                
               φ 
             
             = 
             
               
                 
                   C 
                   L 
                   2 
                 
                 
                   
                     ( 
                     
                       
                         p 
                         f 
                       
                       - 
                       
                         p 
                         i 
                       
                     
                     ) 
                   
                   2 
                 
               
               · 
               
                 πμ 
                 
                   c 
                   t 
                 
               
             
           
         
       
     
     where k is the formation permeability, φ is the formation porosity, p f  is the fluid pressure in the fracture, p i  is the reservoir pressure, μ is the viscosity of the fracturing fluid and c t  is the fluid compressibility. 
     Thus, the method described above may be useful for testing and/or conducting diagnostics on the subterranean formation  14  and otherwise aiding in stimulation design and reservoir development and for estimating reservoir and fracturing characteristics. The method may be particularly useful for tight formations or other formations having low hydraulic conductivity and/or low permeability. 
     Various estimated characteristics provided herein may be used in hydraulic fracturing simulators to history match other parameters of interest (e.g., stress state and in-situ fracture toughness). For example, the methodology described may allow for estimating fracture height and correspondingly the height of the HF confining zone (if any), the leak-off volume V L  and velocity μ L , the leak-off coefficient C L , and other formation flow-related properties. 
     Those of skill in the art will appreciate that many modifications and variations are possible in terms of the disclosed embodiments, configurations, materials, and methods without departing from their scope. Accordingly, the scope of the claims and their functional equivalents should not be limited by the particular embodiments described and illustrated, as these are merely exemplary in nature and elements described separately may be optionally combined.