Patent Publication Number: US-10774614-B2

Title: Downhole tool with assembly for determining seal integrity

Description:
BACKGROUND 
     This section is intended to provide background information to facilitate a better understanding of the various aspects of the described embodiments. Accordingly, it should be understood that these statements are to be read in this light and not as admissions of prior art. 
     Wells are drilled at various depths to access and produce oil, gas, minerals, and other naturally-occurring deposits from subterranean geological formations. The drilling of a well is typically accomplished with a drill bit that is rotated within the well to advance the well by removing topsoil, sand, clay, limestone, calcites, dolomites, or other materials. The drill bit is attached to a drill string that may be rotated to drive the drill bit and within which drilling fluid, referred to as “drilling mud” or “mud,” may be delivered downhole. The drilling mud is used to cool and lubricate the drill bit and downhole equipment and is also used to transport any rock fragments or other cuttings to the surface of the well. The drill string may include a bottom hole assembly (BHA) that includes various electronic tools such as motors, directional sensing devices, generators, and the like. 
     As wells are established it is often useful to obtain information about the well and the geological formations through which the well passes. Information gathering may be performed using tools that are delivered downhole by wireline, tools coupled to or integrated into the drill string, or tools delivered on other types of testing strings. These tools may include logging while drilling (LWD) and measurement while drilling (MWD) tools. Testing strings, which may be used to test a well, include tools such as tester valves, circulations valves, and the like. Many of these downhole tools and devices include regions which need to remain sealed and isolated from fluid that may be present in the downhole environment. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a detailed description of the embodiments of the invention, reference will now be made to the accompanying drawings in which: 
         FIG. 1  depicts a schematic view of an offshore well with a well tubing string, in accordance with one or more embodiments; 
         FIG. 2  depicts a cross-sectional schematic view of a circulating valve, in accordance with one or more embodiments; 
         FIG. 3  depicts a cross-sectional schematic view of a rupture seal section of the circulating valve of  FIG. 2 ; and 
         FIG. 4  depicts a cross-sectional schematic view of an air chamber section of the circulating valve of  FIG. 2 . 
     
    
    
     DETAILED DESCRIPTION 
     The present disclosure provides methods and systems for determining seal integrity in downhole tools. Specifically, the present disclosure provides techniques in which materials that react exothermically with water are placed inside regions of downhole tools where fluids are not to be present. One or more sensors can be used to detect the occurrence of an exothermic reaction, which is an indication of breach of the sealed region. One option is to include the sensor externally of the tool. Placement of the sensor externally of the tool allows for indication of the breach without requiring additional ports or intrusive devices. For illustrative purposes, the present techniques are described in the context of a circulation valve of a well testing string. However, the present techniques can be used with any downhole tool for the detection of the presence of fluid within a region. 
     Referring to the figures,  FIG. 1  depicts a schematic view of an offshore well system  100  with a tubing string  122  in an oil and gas well  102 , in accordance with one or more embodiments. Specifically, in some applications, the tubing string  122  is a well testing string. A floating platform  100  is positioned over the submerged oil or gas well  102  located in the sea floor  104 . The well  102  includes a wellbore  106  that extends from the sea floor  104  to a submerged formation  108  to be tested. The wellbore  106  may be lined by a casing  110  that may be cemented into place. A subsea conduit  112  extends from a deck  114  of the floating platform  100  into a wellhead installation  116 . The floating platform  100  further includes a derrick  118  and a hoisting apparatus  120  for raising and lowering tools to drill, test, and complete the oil or gas well  102 . While the well  102  is illustrated as being an offshore well in  FIG. 1 , the systems, apparatuses, and methods described herein will function equally well in an on-shore well. 
     In some embodiments, the tubing string  122  is lowered into the wellbore  106 . The tubing string  122  may include such tools as a slip joint  123  to compensate for the wave action of the floating platform  100  as the tubing string  122  is lowered into place. The tubing string  122  may also include a tester valve  124 , and a circulation valve  126 . 
     The tester valve  124  is used to control the flow from the formation  104  and provides a downhole closure method to stop the flow. For example, for reservoir pressure transient analysis, it is much preferred to shut in the well downhole instead of at the surface. For a surface shut in, tubing from the surface to the formation is pressurized by the formation so the actual reservoir pressure response is masked. 
     In certain embodiments, the circulation valve  126  may be used to control fluid communication between the annulus  136  and the inside of the tubing string  122 , as will be describe in more detail below with respect to  FIG. 3 . 
     The tester valve  124 , the circulation valve  126 , and the check valve assembly  128  may be operated by fluid annulus pressure exerted by a pump  130  on the deck  114  of the floating platform  100 . Pressure changes are transmitted by a pipe  134  to a well annulus  136  between the casing  110  and the tubing string  122 . Well annulus pressure is isolated from the formation  108  by a packer  138  having an expandable sealing element  132  thereabout set in the casing  110  adjacent to the formation  108 . The packer  138  may be any suitable packer type. 
     The tubing string  122  may also include a tubing seal assembly  140  at the lower end of the tubing string  122 . The tubing seal assembly  140  stabs through a passageway within the packer  138  to form a seal isolating the well annulus  136  above the packer  138  from an interior bore portion  142  of the well immediately adjacent the formation  108  and below the packer  138 . 
     A perforated tail piece  144 , a Tubing Conveyed Perforating (TCP) gun, or other production tube, can be located at the bottom end of the tubing seal assembly  140  to allow formation fluids to flow from the formation  108  into the flow passage of the tubing string  122 . Formation fluid is admitted into the interior bore portion  142  through perforations  146  provided in the casing  110  adjacent the formation  108 . 
     A formation test procedure controls the flow of fluid from the formation  108  through the flow channel in the tubing string  122  by applying and releasing fluid annulus pressure to the well annulus  136  by the pump  130  to operate the tester valve  124 , the circulation valve  126 . The formation test may measure the pressure build-up curves and fluid temperature curves with appropriate pressure and temperature sensors in the tubing string  122 . The system  100  also includes an above-surface control center  121  configured to transmit and receive data with one or more downhole tools. 
       FIG. 2  depicts a cross-sectional schematic view of the circulating valve  126 , in accordance with one or more embodiments. The circulating valve assembly  126  generally has a tubular body and may be installed as a segment of the tubing string  122  and comprising a bore in fluid communication with the tubing string  122 . The circulating valve  126  includes an upper coupling  202 , a rupture disc case  204 , a lower adapter  206 , and an inner mandrel  208 , each of which may be tubular shaped. The upper coupling  202  is configured to couple to a portion of the tubing string  122  above the circulating valve  126 , the lower adapter  206  is configured to couple to a portion of the tubing string  122  below the circulating valve  126 , and the rupture disc case  204  is coupled between upper coupling  202  and the lower adapter  206 . The inner mandrel  208  is located inside the circulating valve  126 . The upper coupling  202 , rupture disc case  204 , and lower adapter  206  may make up an outer casing  201  of the circulating valve  126 . 
     The circulating valve  126  is typically run installed in the wellbore  106  connected to the tubing string  122 . The annulus  136  is formed inside the casing  110  wellbore  106  around the circulating valve  126 . The circulating valve  126  is positioned above of the packer  138 . In this embodiment, the valve assembly has an external shape and size that is substantially the same size and shape as the tubing string. The bore  210  allows tools to pass therethrough. 
     The circulating valve  126  is movable between two configurations, a sealed configuration and a circulating configuration.  FIG. 2  illustrates the circulating valve  126  in the sealed configuration, in which the bore  106  of the circulating valve  126  is sealed off from the annulus  136 . The circulating valve  126 , along with the tubing string  122 , is run into the wellbore  106  with the circulating valve  126  in the run position. When in position at a subterranean location, the packer  138  is set against the well casing  110 , sealing the annulus  136  formed between the outside of the tubing string  122  and the interior wall of the surrounding casing to prevent flow through the annulus past the packer  138 . 
     In the sealed position, the inner mandrel  208  blocks one or more ports  212  formed in the upper coupling  202 . In the circulating position, the inner mandrel  208  moves axially relative to the outer casing  201  from the sealed position. When the inner mandrel  208  is in the circulating position, the one or more ports  202  are no longer blocked, putting the annulus  136  in fluid communication with the bore  210  via the ports  202 . With the circulating valve  126  in the circulating position, fluids, such as for example, drilling mud or produced hydrocarbons can be circulated or pumped out of the wellbore  106  either through the annulus  136  or the interior of the tubing string  122  via the circulating valve  126 . 
     In some embodiments, the circulating valve  126  is put into the circulating position from the sealed position when the pressure in the annulus  136  reaches a threshold level. Specifically, the circulating valve  126  comprises a rupture disc  214  located in the wall of the rupture disc case  204 . The rupture disc  214  is exposed to the annulus  136 , separating the annulus  136  from the inner mandrel  208 , and therefore subject to the annulus pressure. The rupture disc  214  is configured to rupture when the annulus pressure reaches the threshold. When the rupture disc  214  ruptures, the inner mandrel  208  is exposed to the annulus pressure. The rupture disc  214  can be specifically designed or chosen to rupture at the threshold pressure. The annulus pressure then pushes the inner mandrel  208  from the sealed position to the circulating position, causing one or more shear pins  214  to shear. In the embodiment of  FIG. 2 , the annulus pressure pushes the inner mandrel  208  downward, exposing the ports  212 . 
     The circulating valve  126  further includes one or more air chambers  218  bound between the rupture disc case  204  and the inner mandrel  208 . When the circulating valve  126  is in the sealed configuration, the air chamber  218  is at its full volume. When the circulating valve  126  is put into the circulating configuration, the inner mandrel  208  travels into the space held by the air chamber  218 , thereby collapsing the air chamber  218 . In some embodiments, one or more bumpers  220  are located in the air chamber  218  and configured to cushion the inner mandrel  208  as it travels through the air chamber  218 . The circulating valve  126  further includes seals  222  disposed between the inner mandrel  208  and the outer casing  201  to prevent fluid breach. 
     Certain regions of the circulating valve  128 , such as the air chamber and regions adjacent the rupture disc  214  should remain sealed against surrounding fluids while in the sealed configuration. In order to detect if any of these regions has been breached by fluid, a substance  306  that reacts exothermically with water is placed in one or more of the regions. For example, the substance  306  can be placed near the rupture disc  214  or within the air chamber  218 , as further discussed with respect to  FIGS. 3 and 4 . The substance  306  may contain any material that reacts exothermically with water. This may include, but is not limited to, alkali metals and alkaline earth metals. The substance  306  may include a strong acid such as sulfuric acid, anhydrous salt, calcium chloride, and the like. In some embodiments, the substance  306  may be configured to react exothermically with a fluid besides water, such as hydrocarbon. In some embodiments, the substance  306  may be one that reacts endothermically with water. 
     In some embodiments, the substance  306  may include two or more substances that are highly reactive to each other, but require the addition of the water to allow them to mix and react. In another embodiment, both the rupture disc case  204  and the mandrel  208  are made of a non-magnetic material, and magnetic particles are suspended in a salt type ring. When water is not present, the magnetic particles are held in the salt and equally spaced. If water breaches the air chamber  218 , the salt dissolves, causing the magnetic particles to bunch together. A magnetometer can be used to detect such an occurrence, indicating breach of the air chamber  218 . 
       FIG. 3  depicts a cross-sectional schematic view of a rupture disc section of the circulating valve  128  of  FIG. 2 , specifically section a-b of  FIG. 2 . In some embodiments, the rupture disc  214  is formed in the wall of the rupture disc case  204 . Specifically, the rupture disc  214  may located within an orifice  304  formed within the rupture disc case  204  such that when the rupture disc  214  breaks, the orifice will be partially open to flow. However, when the circulating valve  128  is in the sealed configuration, no rupture disc  214  should be intact and prevent fluid from penetrating the circulating valve  128 . Thus, the substance can be placed adjacent the rupture disc  214  on the inside of the circulating valve  128  such that if any fluid were to leak past the rupture disc  214 , an exothermic reaction would take place. The substance may be placed on or near the seam between the rupture disc  214  and the rupture disc case  204  in the orifice  304 , and any other suitable location in fluid communication with the rupture disc  214 . Thus, the seal integrity of the rupture disc  214  can be tested. 
     A sensor  302 , such as a temperature sensor, may be placed on the rupture disc  214  or rupture disc case  204  external to the circulating valve  128 . The sensor  302  is configured to monitor a certain parameter and detect occurrence of an exothermic reaction. For example, a temperature sensor placed on the outside of the rupture disc  214  or rupture disc case  204  can detect occurrence of an exothermic reaction by sensing a sudden temperature rise. The sensor  302  may be a pressure sensor configured to detect a rise in pressure caused by and indicative of an exothermic reaction. The sensor  302  may produce an indication of a leak or communicate to the control center  121 , where an indication is produced. The tool may then be disassembled to determine the cause of the leak or to fix the leak. 
       FIG. 4  depicts a cross-sectional schematic view of an air chamber section of the circulating valve of  FIG. 2 , specifically section b-c of  FIG. 2 . The air chamber  218  is formed between the inner mandrel  208  and the rupture disc case  304 . In some embodiments, the air chamber  218  may be formed in a recess in the inner mandrel  208 . Typically, the air chamber  218  should be kept sealed from any fluid entry such that the volume is available for receiving the inner mandrel  20  when it slides into the second position when the circulating valve  128  is put into the circulating configuration. In order to detect fluid leak into the air chamber  218 , the substance  306  can be placed in the air chamber  218  such that an exothermic reaction occurs if fluid enters the air chamber  218 . In some embodiments, the substance  306  can be placed in the bumpers  220 . In certain such embodiments, the substance  306  is to be applied to the bumper  220  prior to assembly, and the bumper  220  with the substance  306  is then installed into the circulating valve  128 . In other embodiments, the substance  306  can be applied to other areas of the air chambers  218 . 
     In certain such embodiments, a sensor  404 , similar to sensor  302 , may be placed on the rupture disc case  204  external to the circulating valve  128  to monitor a certain parameter and detect occurrence of an exothermic reaction. For example, a temperature sensor can detect occurrence of an exothermic reaction by sensing a sudden temperature rise. The sensor  404  may be a pressure sensor configured to detect a rise in pressure caused by and indicative of an exothermic reaction. The sensor  404  may communicate the sensed data or notifications to the above-surface control center  121 , where an indication is produced. Various intervention steps can then be taken as suitable for the operation. 
     The embodiments discussed herein apply to a circulation valve  128 . However, the technique disclosed herein of applying a substance that reacts exothermically with a fluid such as water can be used to detect the presence of a certain material, such as water, within any type of downhole tool that has a region to be isolated. 
     In addition to the embodiments described above, many examples of specific combinations are within the scope of the disclosure, some of which are detailed below: 
     Example 1 
     A downhole well device for positioning within a well having a fluid, comprising: 
     a sealed chamber; 
     a substance located within the chamber, wherein the substance is exothermically or endothermically reactive with the fluid; and 
     a sensor configured to detect an exothermic reaction or endothermic reaction within the chamber. 
     Example 2 
     The device of example 1, wherein the sensor comprises a temperature sensor, a pressure sensor, or both. 
     Example 3 
     The device of example 1, further comprising: 
     an outer casing; 
     an inner casing at least partially located within the outer casing; 
     seals between the outer and inner casing; 
     wherein the sealed chamber is formed by the outer and inner casings and the seals; and 
     wherein the temperature sensor is located on an outer surface of the outer casing and is configured to sense the temperature of the chamber. 
     Example 4 
     The device of example 1, further comprising a bumper located in the chamber, wherein the substance is located on the bumper or is a part of the bumper. 
     Example 5 
     The device of example 1, wherein the inner casing is movable axially with respect to the outer casing. 
     Example 6 
     The device of example 1, wherein the inner casing comprises a mandrel. 
     Example 7 
     The device of example 1, wherein the substance comprises at least one of alkali metal and an alkaline earth metal. 
     Example 8 
     The device of example 1, wherein the outer casing is coupled to a downhole tubing string or a downhole tubing string. 
     Example 9 
     The device of example 9, wherein the fluid is water. 
     Example 10 
     A downhole well device for positioning within a well having a fluid, comprising: 
     an outer casing comprising a port; 
     an inner casing at least partially located within the outer casing; 
     seals between the inner casing and the outer casing; 
     a rupture disk located in the port; 
     a substance located in a space between the rupture disk and the inner casing, wherein the substance is exothermically reactive with the fluid; and 
     a sensor configured to detect an exothermic reaction within the chamber. 
     Example 11 
     The device of example 10, wherein the sensor comprises a temperature sensor, a pressure sensor, or both. 
     Example 12 
     The device of example 11, wherein the temperature sensor is located external to the outer casing adjacent the rupture disk and configured to sense the temperature of the space externally. 
     Example 13 
     The device of example 10, wherein the substance comprises at least one of an alkali metal and an alkaline earth meter. 
     Example 14 
     The device of example 10, wherein the substance is located on the rupture disk. 
     Example 15 
     The device of example 10, wherein the inner casing is movable axially with respect to the outer casing. 
     Example 16 
     The device of example 10, wherein the fluid is water. 
     Example 17 
     A method of detecting a leak into sealed chamber of a downhole well tool, comprising: 
     sensing a condition of the sealed chamber with a sensor; 
     detecting an indication of an exothermic reaction within the sealed chamber, the exothermic reaction resulting from a fluid being present in the sealed chamber; and 
     producing an indication upon detection of the exothermic reaction. 
     Example 18 
     The method of example 17, comprising sensing a temperature of the sealed chamber externally and detecting a rise in temperature, wherein the rise in temperature is indicative of the exothermic reaction. 
     Example 19 
     The method of example 17, wherein the sealed chamber contains a substance configured to react exothermically in the presence of the fluid. 
     Example 20 
     The method of example 19, wherein the fluid is water. 
     This discussion is directed to various embodiments of the invention. The drawing figures are not necessarily to scale. Certain features of the embodiments may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. Although one or more of these embodiments may be preferred, the embodiments disclosed should not be interpreted, or otherwise used, as limiting the scope of the disclosure, including the claims. It is to be fully recognized that the different teachings of the embodiments discussed may be employed separately or in any suitable combination to produce desired results. In addition, one skilled in the art will understand that the description has broad application, and the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to intimate that the scope of the disclosure, including the claims, is limited to that embodiment. 
     Certain terms are used throughout the description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function, unless specifically stated. In the discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. In addition, the terms “axial” and “axially” generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the central axis. The use of “top,” “bottom,” “above,” “below,” and variations of these terms is made for convenience, but does not require any particular orientation of the components. 
     Reference throughout this specification to “one embodiment,” “an embodiment,” or similar language means that a particular feature, structure, or characteristic described in connection with the embodiment may be included in at least one embodiment of the present disclosure. Thus, appearances of the phrases “in one embodiment,” “in an embodiment,” and similar language throughout this specification may, but do not necessarily, all refer to the same embodiment. 
     Although the present invention has been described with respect to specific details, it is not intended that such details should be regarded as limitations on the scope of the invention, except to the extent that they are included in the accompanying claims.