Abstract:
A method of determining the inflow profile of an injection wellbore, comprising stopping injection of fluid into a formation, the formation intersected by a wellbore having a section uphole of the formation and a section within the formation, monitoring temperature at least partially along the uphole section of the wellbore and at least partially along the formation section of the wellbore, injecting fluid into the formation once the temperature in the uphole section of the wellbore increases, and monitoring the movement of the increased temperature fluid as it moves from the uphole section of the wellbore along the formation section of the wellbore. The monitoring may be performed using a distributed temperature sensing system.

Description:
BACKGROUND OF THE INVENTION  
       [0001]     1. Field of the Invention  
         [0002]     The invention generally relates to a method for use in subterranean wellbores. More particularly, the invention relates to a method used to measure inflow profiles in subterranean injector wellbores.  
         [0003]     2. Description of Related Art  
         [0004]     It is important for an operator of a subterranean injector wellbore, such as for an oil or gas well, to determine the inflow profile of the injector wellbore in order to analyze whether all or just certain parts of a specific zone are injecting fluids therethrough. This determination and analysis is useful in vertical, deviated, and horizontal wellbores. In horizontal wellbores, the amount of fluid flowing through a specific zone tends to decrease from the heel to the toe of the well. Often, the toe and sections close to the toe have very little and sometimes no fluid flowing therethrough. An operator with knowledge of the inflow profile of a well can then attempt to take remediation measures to ensure that a more even inflow profile is created from the heel to the toe of the well.  
         [0005]     Thus, there exists a continuing need for an arrangement and/or technique that addresses one or more of the problems that are stated above.  
       BRIEF SUMMARY OF THE INVENTION  
       [0006]     The invention comprises a method of determining the inflow profile of an injection wellbore, comprising stopping injection of fluid into a formation, the formation intersected by a wellbore having a section uphole of the formation and a section within the formation, monitoring temperature at least partially along the uphole section of the wellbore and at least partially along the formation section of the wellbore, injecting fluid into the formation once the temperature in the uphole section of the wellbore increases, and monitoring the movement of the increased temperature fluid as it moves from the uphole section of the wellbore along the formation section of the wellbore. The monitoring may be performed using a distributed temperature sensing system. 
     
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0007]     The invention is more fully described with reference to the appended drawings wherein:  
         [0008]      FIG. 1  is a schematic illustration of a wellbore utilizing the present invention;  
         [0009]      FIG. 2  is a plot of a geothermal temperature profile along a horizontal wellbore;  
         [0010]      FIG. 3  is a plot showing temperature profiles taken along a wellbore at different points in time, including during injection and while the well is shut-in;  
         [0011]      FIG. 4  is a plot illustrating the movement of a temperature peak along the wellbore and relevant formation; and  
         [0012]      FIG. 5  is a plot of the velocity of the temperature peak of  FIG. 4  as it moves along the wellbore and relevant formation.  
     
    
     DETAILED DESCRIPTION OF THE INVENTION  
       [0013]      FIG. 1  is a general schematic of an injector wellbore utilizing the present invention. A tubing  10  is disposed within a wellbore  12  that may be cased or uncased. Wellbore  12  may be a horizontal or inclined well that has a heel  14  and a toe  16 , or a vertical well. The horizontal section of the well may have a liner, may be open-hole, or may have a continuation of tubing  10  therein. Wellbore  12  intersects a permeable formation  18  such as a hydrocarbon formation. A packer  11  may be disposed around the tubing  10  to sealingly separate the wellbore sections above and below the packer  11 .  
         [0014]     Wellbore  12  is an injector wellbore and the tubing  10  thus has injection equipment  20  (such as a pump) connected thereto near the earth&#39;s surface  22 . Injection equipment  20  may be connected to a tank  23  containing the fluid which is to be injected into formation  18 . Typically, the fluid is injected by the injection equipment  20  through the tubing  10  and into formation  18 . Tubing  10  may have ports adjacent formation  18  so as to allow flow of the fluid into formation  18 . In other embodiments, a liner with slots disposed in the horizontal section of the well may provide the fluid communication, or the horizontal section may be open hole. Perforations may also be made along formation  18  to facilitate fluid flow into the formation  18 .  
         [0015]     A distributed temperature sensing (DTS) system  24  is also disposed in the wellbore  12 . The DTS system  24  includes an optical fiber  26  and an optical launch and acquisition unit  28 .  
         [0016]     In the embodiment shown, the optical fiber  26  is disposed along the tubing  10  and is attached thereto on the outside of the tubing  10 . In other embodiments, the optical fiber  26  may be disposed within the tubing  10  or outside of the casing of the wellbore  12  (if the wellbore is cased). The optical fiber  26  extends through the packer  11  and across formation  18 . The optical fiber  26  may be deployed within a conduit, such as a metal control line. The control line is then attached to the tubing  10  or behind the casing (if the wellbore is cased). The optical fiber  26  may be pumped into the control line by use of fluid drag before or after the control line and tubing  10  are deployed downhole. This pumping technique is described in U.S. Reissue Pat. No. 37,283, which is incorporated herein by reference.  
         [0017]     The acquisition unit  28  launches optical pulses through the optical fiber  26  and then receives the return signals and interprets such signals to provide a distributed temperature measurement profile along the length of the optical fiber  26 . In one embodiment, the DTS system  24  is an optical time domain reflectometry (OTDR) system wherein the acquisition unit  28  includes a light source and a computer or logic device. OTDR systems are known in the prior art, such as those described in U.S. Pat. Nos. 4,823,166 and 5,592,282, both of which are incorporated herein by reference. In OTDR, a pulse of optical energy is launched into an optical fiber and the backscattered optical energy returning from the fiber is observed as a function of time, which is proportional to distance along the fiber from which the backscattered light is received. This backscattered light includes the Rayleigh, Brillouin, and Raman spectrums. The Raman spectrum is the most temperature sensitive, with the intensity of the spectrum varying with temperature, although Brillouin scattering, and in certain cases Rayleigh scattering, are also temperature sensitive.  
         [0018]     Generally, in one embodiment, pulses of light at a fixed wavelength are transmitted from the light source in acquisition unit  28  down the optical fiber  26 . At every measurement point in the optical fiber  26 , light is back-scattered and returns to the acquisition unit  28 . Knowing the speed of light and the moment of arrival of the return signal enables its point of origin along the optical fiber  26  to be determined. Temperature stimulates the energy levels of molecules of the silica and of other index-modifying additives, such as germania, present in the optical fiber  26 . The back-scattered light contains upshifted and downshifted wavebands (such as the Stokes Raman and Anti-Stokes Raman portions of the back-scattered spectrum), which can be analyzed to determine the temperature at origin. In this way, the temperature of each of the responding measurement points in the optical fiber  26  can be calculated by the acquisition unit  28 , providing a complete temperature profile along the length of the optical fiber  26 . In one embodiment, the optical fiber  26  is disposed in a u-shape along the wellbore  12  providing greater resolution to the temperature measurement.  
         [0019]      FIG. 2  shows a graph of the geothermal temperature profile  29  of a generic horizontal wellbore. This profile shows at  30  a gradual increase in temperature as the depth of the well increases, until at  32  a stable temperature is reached along the horizontal section of the wellbore. The geothermal temperature profile is the temperature profile existing in the wellbore without external factors (such as injection). After injection or other external factors end, the wellbore will gradually change in temperature towards the geothermal temperature profile.  
         [0020]     In one embodiment of this invention, in order to determine the inflow profile of a wellbore  12 , the wellbore  12  must first be shut-in so that no injection takes place. The temperature profile of the wellbore  12  changes if there is injection and throughout the shut-in period.  FIG. 3  shows these changes.  
         [0021]     Curve  34  is the temperature profile of the wellbore  12  during injection, wherein the temperature is relatively stable since the injected fluid is flowing through the tubing  10  and into the formation  18 .  
         [0022]     Curve  36  represents a temperature profile of the wellbore  12  taken after injection is stopped and the well is shut-in. Curve  36  is already gradually moving towards the geothermal profile  29 . However, section  40  of curve  36  is changing at a much slower rate than the uphole part of the curve  36  because section  40  represents the area of the formation  18  which absorbed the most fluid during the injection step. Therefore, since this area is in contact with a substantial amount of fluid already injected in the formation  18 , this area takes a longer time to heat or return to its geothermal norm. Of interest, peak  42  is present on curve  36  because peak  42  is the area of wellbore  12  found directly before formation  18  (and not taking fluids). Therefore, a substantial temperature difference exists between peak  42  and section  40 .  
         [0023]     Curve  38  represents a temperature profile of the wellbore  12  taken subsequent to the temperature profile represented by curve  36 . Curve  38  shows that the temperature profile is still heating towards the geothermal norm, but that the difference between peak  44  (peak  42  at a later time) and the section  40  are still apparent.  
         [0024]     The object of this invention is to determine the velocity of the fluid being injected across the length of the formation  18  in order to then determine the inflow profile of such formation  18 . The technique used to achieve this is to re-initiate injection after a relatively short shut-in period and track the movement of the temperature peak ( 42 ,  44 ) by use of the DTS system  24 .  
         [0025]      FIG. 4  shows four curves representing temperature profiles taken over time. Curve  50  is a profile taken during shut-in, curve  52  is a profile taken after injection is re-started, curve  54  is a profile taken after curve  52 , and curve  56  is a profile taken after curve  54 . For purposes of clarity, the entire temperature profile of the wellbore has not been shown. Curve  50  includes a temperature peak  58 A that represents the temperature peak present during shut-in and found directly uphole of formation  18 . Temperature peak  58 A corresponds to temperature peaks  42  and  44  of  FIG. 3 . Once injection is restarted, the slug of heated fluid represented by temperature peak  58 A is essentially “pushed” down the wellbore  12 , as is shown by the temperature peaks  58 B-D in time lapse curves  52 ,  54 , and  56 . The temperature peak  58 A-D, as expected, decreases over time once injection is restarted.  
         [0026]     By tracking the movement of the temperature peak  58 A-D down the wellbore  12  (through use of the DTS system  24 ), an operator can determine the velocity of the temperature peak  58 A-D as it moves down the wellbore  12  and the formation  18  over time. As shown in  FIG. 5 , the velocity of the temperature peak  58 A-D is then plotted against depth across the length of the formation  18 . This plot shows a constant velocity at 60 immediately prior to the temperature peak reaching the formation  18 , a gradual decrease of velocity at 62 as the temperature peak moves away from the uphole boundary of the formation  18 , and a very low and perhaps zero velocity as the peak nears the downhole boundary of the formation  18 . From this plot, one can determine that the downhole portion of the formation  18  (that closer to the toe  16 ) is not receiving much fluid during injection in comparison to the uphole portion of the formation  18 . With this information, one can provide injection inflow profiles across the formation  18 , which profiles can be shown in percentage form (percentage of fluid being injected along the length of the formation  18 ) or quantitative form (with knowledge or a measurement of the actual surface injection rate). Thus, by monitoring the velocity of a heated slug (temperature peaks  58 A-D) across a formation  18 , the injection inflow profile of a wellbore  12  across a formation  18  may be determined.  
         [0027]     Of importance, the shut-in period required to use the present technique is short in relation to the shut-in periods in some comparable prior art techniques. In some prior art techniques, the area of the formation  18  (see section  40  in  FIG. 3 ) and not the area directly uphole of the formation  18  (see peaks  42  and  44  in  FIG. 3 ) is monitored during the warmback period (and not the injection period) to determine the inflow profile. However, in wellbores that have been injecting for a long period of time, the area of the formation  18  (see section  40 ) must be monitored for a substantial period of time before the warmback curves begin to move towards the geothermal gradient and the relevant information can be extracted therefrom. With the present technique, the warmback period can be as short as 24 to 48 hours, since the temperature peaks  42  and  44  (used as previously stated) begin to shift towards the geothermal profile much more quickly. Thus, a process that would take weeks or months to complete using the prior art techniques can now be completed in several days using the present technique.  
         [0028]     While the invention has been disclosed with respect to a limited number of embodiments, those skilled in the art, having the benefit of this disclosure, will appreciate numerous modifications and variations therefrom. It is intended that the appended claims cover all such modifications and variations as fall within the scope of the invention.