Patent Publication Number: US-2015075784-A1

Title: Phased stimulation methods

Description:
RELATED CASES 
     This application claims the benefit of U.S. Provisional Application No. 61/879,886, filed on Sep. 19, 2013, which is incorporated herein by reference. 
    
    
     FIELD OF THE INVENTION 
     The present disclosure relates generally to stimulation of subterranean formations and more particularly to a method of phased stimulation. 
     BACKGROUND 
     Hydrocarbon (e.g., oil, natural gas, etc.) reservoirs may be found in subterranean formations that have little to no porosity (e.g., shale, tight sandstone etc.). The hydrocarbons may be trapped within fractures and pore spaces of the formation. Additionally, the hydrocarbons may be adsorbed onto organic material of the shale formation. The rapid development of extracting hydrocarbons from these unconventional reservoirs can be tied to the combination of horizontal drilling and hydraulic fracturing. Horizontal drilling has allowed for drilling along and within hydrocarbon reservoirs to better capture the hydrocarbons trapped therein. Additionally, more hydrocarbons may be captured by increasing the number of fractures in the formation and/or increasing the size of already present fractures through fracturing or other stimulation. 
     The spacing between fractures as well as the ability to stimulate the fractures naturally present in the rock may be major factors in the success of horizontal completions in unconventional hydrocarbon reservoirs. Effective placement of fractures in deviated or horizontal wells is challenging. This challenge is highlighted in formations with low permeability. As permeability decreases, smaller spacing is generally necessary to effectively recover hydrocarbons from the formation. However, as the spacing between fractures decreases, the stresses associated with the injection of fluids into the formation to create one fracture is believed to create a “shadow” stress in the formation that negatively influences the placement of the next fracture. 
     SUMMARY OF THE INVENTION 
     In one embodiment, a method of stimulating a subterranean formation is provided. The method includes determining a final fracture spacing. The method includes creating a first set of fractures at a first fracture spacing, the first fracture spacing being larger than the final fracture spacing. The method includes allowing production of fluids from the formation through the well bore via the first set of fractures for a period of time. The method includes, after the period of time, creating a second set of fractures. The final fracture spacing is less than or equal to an average fracture spacing between the first set of fractures and the second set of fractures. 
     In an embodiment, a method of phased stimulation of a zone in a subterranean formation is provided. The method includes stimulating the zone via a first set of fractures originating at a well bore and having a first fracture spacing. The method includes allowing primary production from the zone via the first set of fractures. The method includes providing isolation between the first set of fractures and the well bore before the primary production reaches a predetermined threshold. The method includes further stimulating the zone via a second set of fractures originating at the wellbore, wherein at least one of the fractures of the second set of fractures lies between adjacent fractures in the first set of fractures. The method includes allowing production from the zone via the second set of fractures. The method includes removing the isolation between the first set of fractures and the well bore thereby allowing secondary production from the zone via the first set of fractures. 
    
    
     
       BRIEF DESCRIPTION OF THE FIGURES 
         FIG. 1  is a top view on half length of a hydraulic fracture example illustrating the influence of the stresses from one fracture on the next fracture in accordance with conventional fracture placement. 
         FIG. 2  is side view of a formation containing a well prior to placement of fractures in accordance with a certain embodiment of the present disclosure. 
         FIG. 3  is a side view of the formation of  FIG. 2  after a first set of fractures has been placed in accordance with a certain embodiment of the present disclosure. 
         FIG. 4  is a side view of the formation of  FIGS. 2 and 3  after a second set of fractures has been placed in accordance with a certain embodiment of the present disclosure. 
         FIG. 5  is a side view of the formation of  FIGS. 2-4  after a third set of fractures has been placed in accordance with a certain embodiment of the present disclosure. 
         FIG. 6  is a side view of the formation of  FIGS. 2-5  after isolation has been removed and the first, second, and third sets of fractures are producing fluid. 
     
    
    
     DETAILED DESCRIPTION 
     Referring now to the figures,  FIG. 1  shows how the influence of the stress from the first (rightmost) fracture is believed to inhibit the formation of the second (second to right) fracture. Depending on the size and placement of the second fracture, the third fracture (third from right) may be influenced by either or both of the first and second fracture stresses. Likewise, fractures may be negatively influenced throughout a zone, even moving beyond a particular stage (e.g., the four leftmost fractures might influence the next stage of four fractures and those fractures might influence the next stage of four fractures). Thus, the traditional approach has been to either provide larger fracture spacing than otherwise would be desirable, in order to prevent interference from other fractures or provide the desired spacing and accept the effects of the interference. One alternative to these approaches is described in U.S. 2012/0325462, where fractures are initiated in an alternate order than the aforementioned right to left. While U.S. 2012/0325462 claims to provide improvements by negating the directional impact of the stresses, it is believed that the magnitude of the stresses are still problematic and, unlike the present disclosure, U.S. 2012/0325462 does not consider production of formation fluid as a way to alleviate the stresses. Further, the fracture spacings of U.S. 2012/0325462 are in the range of 150 ft to 250 ft and it is believed that the present disclosure would allow for spacings well below 100 ft. Finally, U.S. 2012/0325462 proposes complex fractures which are unnecessary in accordance with the embodiments described below. Specifically, in U.S. 2012/0325462, spacings between fractures must be sufficiently large to provide a stress-free zone in which a complex fracture can be formed. The embodiments described below, on the other hand, do not require such large spacing or complex fractures. 
     One method of stimulating a subterranean formation  10  having a well bore  12  therein includes (1) determining a threshold stress value indicative of presence of a stress shadow (e.g., by field or other estimations based on formation characteristics), (2) obtaining a formation stress value (e.g., by measurements taken onsite, by field estimations, by calculations, or otherwise), (3) allowing production from the subterranean formation  10  when the stress shadow is present (i.e., when the measured stress value exceeds the threshold stress value), and (4) ceasing production when the stress shadow has dissipated (i.e, when the measured stress value drops below the threshold stress value). 
       FIGS. 2-6  illustrate one method of stimulating the subterranean formation  10  having the well bore  12  therein. The well bore  12  provides a pathway for fluids (e.g., hydrocarbons) from a zone  14  to move to the surface  16 . Fractures  21 - 29 , originating at the exterior surface of the well bore  12  provide fluid communication between the zone  14  and the well bore  12 , allowing the fluids from the zone  14  to exit the subterranean formation  10 , move into the well bore  12  and up to the surface  16 . As illustrated, the methods describe a horizontal or deviated well bore  12 . However, the methods could similarly be used in a vertical well bore. 
     The first step of the method of  FIGS. 2-6  involves determining a final fracture spacing  18 . In  FIG. 2 , the final fracture spacing  18  represents the desired spacing between two adjacent fractures (not yet present in the illustration of  FIG. 2 ) after all fractures have been placed (see  FIG. 6 ). The desired spacing may be calculated or otherwise determined on the basis of the minimum economic production rate, taking into account formation porosity, hydrocarbon saturation, permeability, and costs associated with completion and production. The final spacing  18  may be an economically optimized fracture spacing and the step of determining the final spacing  18  might involve determining the economically optimized fracture spacing. Such determination might involve calculations of net present value, and accounting for various factors including but not limited to current oil and gas prices, operational costs, and capabilities of the facilities. In some instances, the final fracture spacing  18  might vary along the length of the well bore  12  or even within the zone  14  of interest. However, in the interest of simplicity, the final fracture spacing  18  is illustrated as having a uniform dimension. In some embodiments, the final fracture spacing  18  may be less than 500 ft., less than 300 ft., less than 200 ft., less than 180 ft., less than 170 ft., less than 160 ft., less than 150 ft., less than 140 ft., less than 130 ft., less than 120 ft., less than 110 ft., less than 100 ft., less than 90 ft., less than 80 ft., less than 70 ft., less than 60 ft., less than 50 ft., less than 40 ft., less than 30 ft., or even less than 20 ft. 
     Referring now to  FIG. 3 , a first set of fractures  21 ,  22 ,  23  are created at a first fracture spacing  30 . The first fracture spacing  30  is larger than the final fracture spacing  18 . In this illustration, the first fracture spacing  30  is approximately four times the final fracture spacing  18 . In embodiments with two sets of fractures, the first fracture spacing  30  may be about twice the final fracture spacing  18 . In embodiments with more than three sets of fractures, the first fracture spacing  30  may be more than four times the final fracture spacing  18 . After the first set of fractures  21 ,  22 ,  23  are created, hydrocarbons or other fluid  32  from the formation  10  are produced through the well bore  12  via the first set of fractures  21 ,  22 ,  23  for a period of time. The period of time might be determined based on providing sufficient time to permit the relief of stress created by the first set of fractures  21 ,  22 ,  23 . 
     The production of fluids  32  is believed to relieve the pore pressure thus relieving the stress in the rock over time. By allowing fluid  32  to leave the formation  10 , it is thought that the stresses caused by fracturing may be alleviated in the region around such fractures. Such reduction in stresses may allow for a superior fracture to be created between existing fractures, as compared to fractures created without allowing for such stress relief. Thus, production of fluids  32  may be permitted until a predetermined threshold is reached. In one example, the predetermined threshold may be a time of production from the formation  10 . While allowing for a large time to pass might provide for more stress relief, it is thought that the period of time for production between formation of the first set of fractures  21 ,  22 ,  23  and formation of the second set of fractures  24 ,  25  may be relatively short. Such period of time might be less than a year, from 6 months to a year, from 1 to 6 months, from 1 week to 1 month, or from 1 hour to 1 week. In some instances, the period of time might be as small as a few days or even within a few hours. An alternate predetermined threshold may be a percentage of a maximum projected production from the formation  10 . While allowing for a large percentage of the maximum projected production might provide for more stress relief, it is thought that the production between formation of the first set of fractures  21 ,  22 ,  23  and formation of the second set of fractures  24 ,  25  may be relatively small. Such production might be less than 50% of the maximum projected production, less than 25% of the maximum projected production, less than 5% of the maximum projected production, or less than 1% of the maximum projected production. In some instances, the production may be as small as a tenths of a percent or even a few hundredths of a percent. Other alternatives to time and production volumes may be used in the embodiments described, so long as some method of feedback on whether sufficient relief of the stress caused by a particular set of fractures has occurred via production. 
     Once the stress created by the first set of fractures  21 ,  22 ,  23  has been relieved, the production of fluid  32  from the formation  10  via the first set of fractures  21 ,  22 ,  23  may be stopped by plugging the fractures  21 ,  22 ,  23 , or otherwise providing isolation between the first set of fractures  21 ,  22 ,  23  and the well bore  12 . Such isolation may be provided through any of a number of methods. For example, as illustrated in  FIG. 4 , tubing  38  may be run in the casing  40  lining the well bore  12 . The tubing  38  may have external packers  42  used for isolation. Alternative means of isolation include external casing packers, production liners, expandables, coiled tubing via sleeve that opens and closes via ball drop, hydraulics, or otherwise, chemical isolation, or any number of other methods of isolating fractures. 
     Referring now to  FIG. 4 , once the stress created by the first set of fractures  21 ,  22 ,  23  has been released via production of fluid  32 , a second set of fractures  24 ,  25  is created. It is believed that the reduction in fluid  32  in the formation  10  will allow placement of the second set of fractures  24 ,  25  between (e.g., in the middle of) the first set of fractures  21 ,  22 ,  23  without significant resistance. An average fracture spacing  34  between the first set of fractures  21 ,  22 ,  23  and the second set of fractures  24 ,  25  is equal to or greater than the final fracture spacing  18 . Stated otherwise, the final fracture spacing  18  is less than or equal to the average fracture spacing  34  between adjacent fractures in the set of fractures including the first set of fractures  21 ,  22 ,  23  and the second set of fractures  24 ,  25 . 
     As illustrated in  FIG. 4 , the average fracture spacing  34  is about twice the final fracture spacing  18 . However, in some embodiments, two sets of fractures may be sufficient. In those embodiments, the average fracture spacing  34  may be equal to the final fracture spacing  18 . Thus, the first fracture spacing  30  might be double the final fracture spacing  18  when two sets of fractures or sufficient, and the first fracture spacing  30  will be more than double the final fracture spacing  18  in embodiments where more than two sets of fractures are utilized. If two sets of fractures are sufficient, isolation of the first set of fractures  21 ,  22 ,  23  may be removed and production of formation fluid  32  may proceed through both the first and second sets of fractures  21 ,  22 ,  23 ,  24 ,  25 . If further fractures are desired, isolation of the first set of fractures  21 ,  22 ,  23  may remain. After the second set of fractures  24 ,  25  are created, hydrocarbons or other fluid  32  from the formation  10  are produced through the well bore  12  via the second set of fractures  24 ,  25  for a second period of time. 
     The second period of time might be determined based on providing sufficient time to permit the relief of stress created by the second set of fractures  24 ,  25 . Such period of time might be less than a year. For example, the second period of time might be anywhere between 1 and 6 months. In some instances, the second period of time might be as small as a few days or even a few hours. Once the stress created by the second set of fractures  24 ,  25  has been relieved, the production of fluid  32  from the formation  10  via the second set of fractures  24 ,  25  may be stopped by plugging the fractures  24 ,  25 , or otherwise providing isolation between the second set of fractures  24 ,  25  and the well bore  12 . 
     Referring now to  FIG. 5 , once the stress created by the second set of fractures  24 ,  25  has been released via production of fluid  32 , a third set of fractures  26 ,  27 ,  28 ,  29  is created. An average fracture spacing  36  between the first set of fractures  21 ,  22 ,  23 , the second set of fractures  24 ,  25 , and the third set of fractures  26 ,  27 ,  28 ,  29  is equal to or greater than the final fracture spacing  18 . Stated otherwise, the final fracture spacing  18  is less than or equal to the average fracture spacing  36  between adjacent fractures in the set of fractures including the first set of fractures  21 ,  22 ,  23 , the second set of fractures  24 ,  25 , and the third set of fractures  26 ,  27 ,  28 ,  29 . 
     As illustrated in  FIG. 5 , the average fracture spacing  36  is approximately equal to the final fracture spacing  18 . However, if the process were to be repeated in additional iterations, the final fracture spacing  18  might be smaller than the average fracture spacing  36 . Once all iterations are complete, all isolation (e.g., the tubing  38  and external packers  42 ) may be removed to allow for production of fluid  32  through all fractures  21 - 29 , as shown in  FIG. 6 . 
     A method of phased stimulation of the zone  14  in the subterranean formation  10  can also be described with respect to  FIGS. 2-6 . First, the zone  14  is stimulated via the first set of fractures  21 ,  22 ,  23  originating at the well bore  12  and having the first fracture spacing  30 . Such stimulation may be in the form of hydraulic fracturing, acid fracturing, matrix stimulation, and the like. Next, primary production of fluid  32  is allowed from the zone  14  via the first set of fractures  21 ,  22 ,  23  until a predetermined threshold is reached. The predetermined threshold may represent a value indicating a stress relief level has been reached. As described above, the predetermined threshold may be a time of production from the zone or the predetermined threshold may be a percentage of a maximum projected production from the zone. Additionally, other measurements may provide an indication that desirable stress relief has occurred. For example, the predetermined threshold may use feedback in the form of pressure levels, temperatures, produced fluid volumes, flow back fluid volumes, etc. for an indication that suitable stress reduction has occurred. Then, isolation is provided between the first set of fractures and the well bore  12 . The zone  14  is further stimulated via the second set of fractures  24 ,  25  originating at the wellbore  12 . At least one of the fractures  24 ,  25  of the second set of fractures  24 ,  25  lies between adjacent fractures of the first set of fractures  21 ,  22 ,  23 . As illustrated, second set fracture  24  lies between adjacent first set fractures  21  and  22  and second set fracture  25  lies between adjacent first set fractures  22  and  23 . Next, fluid  32  is allowed to be produced from the zone  14  via the second set of fractures  24 ,  25 . Then, the isolation between the first set of fractures  21 ,  22 ,  23  and the well bore  12  is removed, allowing secondary production from the zone  14  via the first set of fractures  21 ,  22 ,  23 . 
     The primary production from the zone  14  via the first set of fractures  21 ,  22 ,  23  is less than the production from zone  14  via both the first and second sets of fractures  21 - 25 . Likewise, if a third set of fractures  26 - 29  is provided, the production from the combined first second and third set of fractures is greater than the production from the first and second sets of fractures. Thus, the primary production from the zone  14  is less than a maximum production from the zone  14 . Further, the primary production from the zone  14  may be less than a maximum economical production from the zone. Such maximum economical production from the zone  14  might be less than the maximum production available from the zone  14 , but might represent the most profitable amount of production when accounting for costs involved. Generally, the primary production from the zone  14  will be less than the maximum economical production. However, it is thought that the sacrifice of maximum economical production in the primary production is outweighed by the benefit provided by superior communication with the zone  14  via the second set of fractures  24 ,  25 , the optional third set of fractures  26 - 29 , and any additional iterations provided by repeating the process. 
     Similarly, after the processes described herein, any of the fractures may be re-stimulated in a secondary or remedial operation. In such a process, a set of fractures may be created, stimulated, and may produce before being isolated while another set of fractures is stimulated. Then, both sets of fractures may produce for some time before either or both sets of fractures is re-stimulated and may produce once again. Furthermore, methods analogous to those above could be used for operations involving other formation treatments. For example, matrix stimulation may benefit from methods such as those described herein. 
     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.