Patent Publication Number: US-8522879-B2

Title: Method and apparatus for controlling fluid flow into a borehole

Description:
BACKGROUND 
     To form a borehole in a formation, a drilling assembly (also referred to as the “bottom hole assembly” or the “BHA”) carrying a drill bit at its bottom end is conveyed downhole. The borehole may be used to store fluids, such as CO2 sequestration, in the formation or obtain fluids, such as hydrocarbons or water, from one or more production zones in the formation. Several techniques may be employed to stimulate hydrocarbon production. For example, a plurality of boreholes (also “wellbores” or “wells”), such as a first and second borehole, may be formed in a formation. The first borehole is an injection borehole and the second borehole is a production borehole. A flow of pressurized fluids from the first borehole cause flow of formation fluids to the production borehole. Specifically, the fluid is flowed downhole within a tubular disposed in the first or injection borehole. One or more flow control apparatus, such as a valve, is located in the tubular to control the pressurized fluid flow into the formation. The pressurized fluid then causes an increased pressure within the formation resulting in flow of formation fluid into a producing string located in the second borehole. A surface fluid source, such as a pump, provides the pressurized injection fluid to each flow control apparatus downhole. 
     If the fluid source shuts down or malfunctions, a pressure differential occurs between the formation zone receiving the injected fluid and the fluid inside the tubular. Specifically, a pressure caused by injecting fluid into a zone of the formation is significantly higher than the hydrostatic pressure within the tubular. Communication of fluid across the pressure differential can cause crossflow from the high pressure zone to other lower pressure zones in the formation. The flow from the high pressure zone can cause flow of sand and debris into the tubular and lower pressure zones, inhibiting flow paths and causing damage to the tubular string. In addition flow of fluid from high pressure zone can cause a high pressure wave or water hammer of fluid to propagate uphole in the tubular. The high pressure wave can damage equipment within the tubular string and at the surface. 
     Devices for flow control of injection fluid from the tubular to the formation zone are controlled from the surface. A control signal to close the device may take several minutes to communicate from the surface. Due to the delayed control signal, the device remains open after a pump shut down, leading to communication of the pressure differential (between the formation and tubular) and resulting cross flow and pressure wave. 
     SUMMARY 
     In one aspect, a flow control apparatus for use in a borehole is provided. The apparatus includes a tubular body, a check valve sleeve and a check valve, wherein a change of a pressure inside the check valve sleeve causes the check valve to control fluid communication between the check valve sleeve and the borehole outside the tubular body. 
     In another aspect, a method for controlling fluid flow between a borehole and a tubular is provided, wherein the method includes directing a fluid downhole via a string to a tubular body. The method further includes increasing a first pressure of the fluid within the string, wherein increasing the first pressure to a selected level causes a check valve to move to an open position, wherein the selected level is greater than a second pressure of a borehole annulus outside the tubular. The method also includes directing the fluid from the string to the borehole annulus via the open check valve. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The disclosure herein is best understood with reference to the accompanying figures in which like numerals have generally been assigned to like elements and in which: 
         FIG. 1  is a schematic view of an embodiment of a system that includes a production tubular and injection apparatus; 
         FIG. 2  is a side view of an exemplary flow control apparatus in a closed position; 
         FIG. 3  is a side view of the exemplary flow control apparatus in a choked position; 
         FIG. 4  is a side view of the exemplary flow control apparatus in an open position; and 
         FIG. 5  is a side view of the exemplary flow control apparatus in a locked open position. 
     
    
    
     DETAILED DESCRIPTION 
     Referring initially to  FIG. 1 , there is shown an exemplary borehole system  100  that includes a borehole  110  drilled through an earth formation  112  and into production zones or reservoirs  114  and  116 . The borehole  110  is shown lined with an optional casing having a number of perforations  118  that penetrate and extend into the formation production zones  114  and  116  so that formation fluids or production fluids may flow from the production zones  114  and  116  into the borehole  110 . The exemplary borehole  110  is shown to include a vertical section  110   a  and a substantially horizontal section  110   b . The borehole  110  includes a string (or production tubular)  120  that includes a tubular (also referred to as the “tubular string” or “base pipe”)  122  that extends downwardly from a wellhead  124  at surface  126  of the borehole  110 . The string  120  defines an internal axial bore  128  along its length. An annulus  130  is defined between the string  120  and the borehole  110 , which may be an open or cased borehole depending on the application. 
     The string  120  is shown to include a generally horizontal portion  132  that extends along the deviated leg or section  110   b  of the borehole  110 . Injection assemblies  134  are positioned at selected locations along the string  120 . Optionally, each injection assembly  134  may be isolated within the borehole  110  by a pair of packer devices  136 . Although only two injection assemblies  134  are shown along the horizontal portion  132 , a large number of such injection assemblies  134  may be arranged along the horizontal portion  132 . Another injection assembly  134  is disposed in vertical section  110   a  to affect production from production zone  114 . In addition, a packer  142  may be positioned near a heel  144  of the borehole  110 , wherein element  146  refers to a toe of the borehole. Packer  142  isolates the horizontal portion  132 , thereby enabling pressure manipulation to control fluid flow in borehole  110 . 
     As depicted, each injection assembly  134  includes equipment configured to control fluid communication between a formation and a tubular, such as string  120 . The exemplary injection assemblies  134  include one or more flow control apparatus or valves  138  to control flow of one or more injection fluids between the string  120  and production zones  114 ,  116 . A fluid source  140  is located at the surface  126 , wherein the fluid source  140  provides pressurized fluid via string  120  to the injection assemblies  134 . Accordingly, each injection assembly  134  may provide fluid to one or more formation zone ( 114 ,  116 ) to induce formation fluid to flow to a second production string (not shown). 
     Injection fluids may include any suitable fluid used to cause a flow of formation fluid from formation zones ( 114 ,  116 ) to a production borehole and string. Further, injection fluids may include a fluid used to reduce or eliminate an impediment to fluid production, such as an acid. As used herein, the term “fluid” or “fluids” includes liquids, gases, hydrocarbons, multi-phase fluids, mixtures of two of more fluids, water and fluids injected from the surface, such as water and/or acid. Additionally, references to water should be construed to also include water-based fluids; e.g., brine, sea water or salt water. 
     In an embodiment, injection fluid, shown by arrow  142 , flows from the surface  126  within string  120  (also referred to as “tubular” or “injection tubular”) to injection assemblies  134 . Flow control apparatus  138  (also referred to as “injection devices” or “valves”) are positioned throughout the string  120  to distribute the fluid based on formation conditions and desired production. In one exemplary embodiment, the flow control apparatus  138  is configured to open to allow fluid to flow from tubular string  122  to borehole  110  when a fluid pressure inside the tubular string  122  reaches a first level or value. In addition, the flow control apparatus  138  is configured to close to shut off or restrict flow of the fluid from the tubular string  122  when the fluid pressure is lowered to a second level that is less than a pressure inside the borehole  110 . Accordingly, the flow control apparatus  138  moves to a closed position shortly after a stoppage of pumping by the fluid source  140 . The closed position prevents or restricts a pressure differential from being communicated between the tubular string  122  and borehole  110 . Thus, flow of fluid from the production zone into the string  120  is restricted to reduce cross flow into other zones. As discussed in detail below, exemplary flow control apparatus  138  are controlled by a pressure level inside the tubular string  122 , thereby improving performance of an injection process while reducing damage to equipment in the tubular string  122 . 
       FIG. 2  is a side sectional view of an exemplary flow control apparatus  200  to be placed downhole within the borehole  110  ( FIG. 1 ). The flow control apparatus  200  includes a tubular body  202 , an insert sleeve  204 , a check valve  206  and a protrusion  208  located on the check valve  206 . The flow control apparatus  200  also includes a check valve sleeve  210  and biasing member  212  coupled to the check valve  206 . A flowbore  214  is in fluid communication with the surface  126  via tubular string  122  ( FIG. 1 ). Upper seal  216  and lower seal  218  prevent fluid communication between the flowbore  214  and flow paths outside the check valve sleeve  210 . In an embodiment, the protrusion  208  (also referred to as a “bean”) is an annular protrusion from the check valve  206  that is configured to create a pressure drop as a fluid flows across the protrusion  208 . 
     The depicted flow control apparatus  200  in a closed position, wherein the insert sleeve  204  and check valve are both in a closed position to restrict fluid communication between the flowbore  214  and a borehole annulus  232 . Specifically, the insert sleeve  204  is positioned to block a passage  220  in the tubular body  202 , wherein seals  223  restrict fluid flow inside the insert sleeve  204 . In the closed position, a passage  222  in the insert sleeve  204  is not aligned with the passage  220 . In addition, the check valve  206  blocks a passage  224  in the check valve sleeve  210 . A seal  228  is located between the check valve  206  and check valve sleeve  208 . The seal  228  restricts fluid flow between the flowbore  214  and outside the check valve sleeve  210 . The flow control apparatus  200  may be in the closed position during run in or prior to production using an injection process. In the closed position, fluid communication is prevented or restricted between the flowbore  214  and the borehole annulus  232 . The position of insert sleeve  204  is coupled to and controlled by a controller  230  via control lines  231 . The controller  230  may be located in any suitable location, such as the surface  126  ( FIG. 1 ). The position of check valve  206  is controlled by the biasing member  212  and the pressures of fluid outside (Po) and inside (P 1 ) the tubular body  202 , as will be described in further detail below. 
       FIG. 3  is a side sectional view of the exemplary flow control apparatus  200  in a choking position. The check valve sleeve  204  has been moved axially to a first open position, wherein the passages  220  and  222  are aligned to enable fluid communication between an annular cavity  302  and the borehole annulus  232 . The annular cavity  302  is defined as substantially between the check valve sleeve  210  and insert sleeve  204 . As depicted, fluid communication between the annular cavity  302  and the borehole annulus  232  causes the pressure in both areas to be equal (P O ). The check valve  206  (also referred to as a “poppet”) remains in the closed position, thereby choking fluid flow between the flowbore  214  and borehole annulus  232 . The biasing member  212  remains in an expanded state, wherein the expanded biasing member  212  provides a downward closing force on the check valve  206 . Further, P O  is a higher pressure than P I , thereby causing an additional downward closing force on the check valve  206 . It should be noted that the terms “blocked,” “restricted,” “closed” and “shut off” with respect to fluid communication and positions may include partially, substantially and completely restricting fluid communication, depending on application needs. 
     As discussed below, a fluid flow  304  provided by fluid source  140  ( FIG. 1 ) may increase the pressure P I  inside the flowbore  214  to cause an opening force that overcomes the closing force of the biasing member  212  and pressure P O . As depicted, the check valve  206  sits on a seat  306  in the closed position, wherein an outer portion of the lower surface  308  of the check valve  206  contacts the seat  306 . The remaining inner portion of surface  308  is exposed to the fluid and pressure P I , wherein the increase in pressure creates an upward opening force on the surface  308  and check valve  206 . As depicted, the controller  230  has moved the insert sleeve  204  axially to enable fluid communication between the borehole annulus  232  and annular cavity  302 . Thus, the position of check valve  206  and resulting fluid communication between flowbore  214  and annulus  232  is controlled by manipulating the level of pressure P I . The closed position of the check valve  206  prevents a pressure differential from being communicated between the flowbore  124  and in the borehole  110  reducing occurrences of cross-flow between zones. 
       FIG. 4  is a side sectional view of the exemplary flow control apparatus  200  in an open injection position. The check valve sleeve  204  remains in the first open position, wherein the passages  220  and  222  are aligned to enable fluid communication between an annular cavity  302  and the borehole annulus  232 . Further, the pressure P I  has been increased to cause the check valve  206  to move open axially (along axis  404 ). Accordingly, the opening force caused by P I  acts upon surface  308  to lift the check valve  206 , overcoming the closing force of the biasing member  212  and pressure P O  inside the annular cavity  302 . As depicted, the biasing member  212  is compressed and the position of check valve  206  is open. Thus, a flow path  400  is provided within the flow control apparatus  200 . In an embodiment, the flow path  400  allows fluid communication from the flowbore  214  to the borehole annulus  232 , wherein the fluid flow  304  is pressurized to provide an injection of fluid into a formation zone. Flow of fluid along flow path  400  and across the protrusion  208  of the check valve  206  causes a pressure drop after flowing through passage  402 , thereby stabilizing the open position of the check valve  206 . Thus, the closed check valve  206  remains open until P I  drops to a pressure level that is lower than P O , wherein the closing forces of the biasing member  212  and pressure P O  cause the check valve  206  to close. The check valve  206  thereby prevents fluid communication of the pressure differential (P O  and P I ) between the borehole annulus  232  and flowbore  214 . The pressure P I  may drop due to a pump shut down or malfunction in fluid source  140  ( FIG. 1 ) 
       FIG. 5  is a side sectional view of the exemplary flow control apparatus  200  in a locked open position. The locked open position may be used to enable of fluid flow from the borehole annulus  232  into the flowbore  214 , depicted by flow arrows  500  and  502 , when pressure P I  is less than or about equal to pressure P O . In the embodiment, the insert sleeve  204  has been moved to a second open position, aligning passages  220  and  222 . The controller  230  causes the insert sleeve  204  to move upward to a fully open position, wherein a protrusion  504  from the insert sleeve  204  engages and lifts a lip  506  of the check valve  206  as it moves upward. Thus, the locked open position is “locked” by the insert sleeve  204  in a fully open position. 
     In an exemplary embodiment, the locked open position enables fluid flow from the borehole annulus  232  to the flowbore  214  after an acid fluid has flowed into the borehole annulus  232  to break up debris impeding fluid flow into the formation. After acid injection, it is desirable to flow the acid and broken up debris to the surface to clean the borehole annulus  232 , thereby enabling production to resume. Accordingly, the depicted locked open position allows fluid flow from the borehole annulus  232  into the flowbore  214  and uphole  502  to clean an area for future injection operations. In another embodiment, the locked position allows formation fluid to flow into the flowbore  214  and tubular string  122  ( FIG. 1 ) to determine various flow parameters downhole, such as pressure and temperature. The determined parameters provide operators with information used to adjust production operations. 
     As shown in  FIGS. 1-5 , the flow control apparatus  200  provides an apparatus and method for controlling fluid flow from the tubular string  122  to the borehole annulus  232 . Specifically, the position of the check valve  206  controls fluid communication between the borehole annulus  232  and the check valve sleeve  210 , wherein the check valve  206  position is controlled by a fluid pressure level within the check valve sleeve  210 . For example, when the fluid source  140  pumping system fails, the pressure within the tubular string  122  and check valve sleeve  210  drops or is reduced, thereby moving the check valve sleeve  210  closed and restricting fluid communication between the borehole annulus  232  and tubular string  122 . 
     In an exemplary embodiment, the flow control apparatus  200  is run in at the closed position ( FIG. 2 ), wherein the insert sleeve  204  is then moved to the open position by the controller  230  ( FIG. 3 ). Then, a fluid pressure increase within the tubular string  122  and check valve sleeve  210  moves the check valve  206  to an open position ( FIG. 4 ). The open position of the check valve  206  and the insert sleeve  204  provides fluid communication for injection fluid flow from the check valve sleeve  210  to the borehole annulus  232 . When the pressure of the fluid inside the check valve sleeve  210  is decreased to a selected level below the borehole pressure, the check valve  206  is moved to a closed position, thereby restricting a flow path between the check valve sleeve  210  and borehole annulus  232 . Thus, when the fluid source  140  ( FIG. 1 ) shuts off, the pressure reduction within the check valve sleeve  210  prevents damage caused by communication of a pressure differential between the borehole annulus  232  and check valve sleeve  210 . 
     While the foregoing disclosure is directed to certain embodiments, various changes and modifications to such embodiments will be apparent to those skilled in the art. It is intended that all changes and modifications that are within the scope and spirit of the appended claims be embraced by the disclosure herein.