You are an expert at summarizing long articles. Proceed to summarize the following text:

You are an expert at summarizing long articles. Proceed to summarize the following text: 
BACKGROUND 
     In most offshore drilling operations, a wellhead at the sea floor is positioned at the upper end of the subterranean wellbore lined with casing, a blowout preventer (“BOP”) stack is mounted to the wellhead and a lower marine riser package (“LMRP”) is mounted to the BOP stack. The upper end of the LMRP typically includes a flex joint coupled to the lower end of a drilling riser that extends upward to a drilling vessel at the sea surface. A drill string is hung from the drilling vessel through the drilling riser, the LMRP, the BOP stack and the wellhead into the wellbore. 
     During drilling operations, drilling fluid, or mud, is pumped from the sea surface down the drill string, and returns up the annulus around the drill string. In the event of a rapid invasion of formation fluid into the annulus, commonly known as a “kick,” the BOP stack and/or LMRP may actuate to help seal the annulus and control the fluid pressure in the wellbore. In particular, the BOP stack and the LMRP include closure members, or cavities, designed to help seal the wellbore and prevent the release of high-pressure formation fluids from the wellbore. Thus, the BOP stack and LMRP function as pressure control devices. 
     For most subsea drilling operations, hydraulic fluid for operating the BOP stack and the LMRP is provided using a common control system physically located on the surface drilling vessel. However, the common control system may become inoperable, resulting in a loss of the ability to operate the BOP stack. As a backup, or even possibly a primary means of operation, hydraulic fluid accumulators are filled with hydraulic fluid under pressure. The amount and size of the accumulators depends on the anticipated operation specifications for the well equipment. 
     An example of an accumulator includes a piston accumulator, which includes a hydraulic fluid section and a gas section separated by a piston movable within the accumulator. The hydraulic fluid is placed into the fluid section of the accumulator and pressurized by injecting gas (typically inert gas, e.g., nitrogen) into the gas section. The fluid section is connected to a hydraulic circuit so that the hydraulic fluid may be used to operate the well equipment. As the fluid is discharged, the piston moves within the accumulator under pressure from the gas to maintain pressure on the remaining hydraulic fluid until full discharge. 
     The ability of the accumulator to operate a piece of equipment depends on the amount of hydraulic fluid in the accumulator and the pressure of the gas. Thus, there is a need to know the volume of the hydraulic fluid remaining in an accumulator so that control of the well equipment may be managed. Measuring the volume of hydraulic fluid in the accumulator over time can also help identify if there is a leak in the accumulator or hydraulic circuit or on the gas side of the piston. 
     Currently, the ability of an accumulator to power equipment is determined by measuring the pressure in the hydraulic circuit downstream of the accumulator. However, pressure is not an indicator of the overall capacity of an accumulator to operate equipment because the volume of hydraulic fluid remaining in the accumulator is not known. Also, accumulators are typically arranged in banks of multiple accumulators all connected to a common hydraulic circuit, therefore, the downstream pressure measurement is only an indication of the overall pressure in the bank, not per individual accumulator. 
     A possible way of determining the volume of hydraulic fluid remaining in the accumulator is to use a linear position sensor such as a cable-extension transducer or linear potentiometer that attaches inside the accumulator to measure the movement of the internal piston. However, these electrical components may fail and because the discharge of hydraulic fluid may be abrupt, the sensors may not be able to sample fast enough to obtain an accurate measurement. 
     Another method of determining the volume of hydraulic fluid is through the use of physical position indicators that extend from the accumulator. These indicators only offer visual feedback though and are insufficient for remote monitoring and pose a significant challenge to maintaining the integrity of the necessary mechanical seals under full operating pressures. 
     Through-the-wall sensors (e.g., Hall effect sensors) have also been considered. However, the thickness and specifications of an accumulator wall is such that these types of sensors are not always able to penetrate the material. 
     SUMMARY 
     In accordance with the invention, a system for determining the location of a movable element within a container is provided in which a circuit is created between elements in the container, the movable element, and a power source. As the movable element moves along the longitudinal axis of the container, the circuit&#39;s electrical characteristics (e.g., voltage, resistance, current) vary in proportion to the length of the circuit. Measurement of these electrical characteristics allows for precise determination of the movable element&#39;s location relative to the container. In commercial embodiments, the invention can be utilized to determine fluid volumes in accumulators used for controlling subsea equipment by monitoring the location of a piston within a hydraulic fluid accumulator. This invention overcomes prior art systems because, among other reasons, it enables remote monitoring, maintains system integrity, and functions irrespective of the container wall thickness. 
     This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter. 
    
    
     
       DRAWINGS 
       For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which: 
         FIG. 1  shows a schematic view of an offshore system for drilling and/or producing a subterranean wellbore with an embodiment of a measurement system; 
         FIG. 2  shows an elevation view of the subsea BOP stack assembly and measurement system of  FIG. 1 ; 
         FIG. 3  shows a perspective view of the subsea BOP stack assembly and measurement system of  FIGS. 1 and 2 ; 
         FIG. 4  shows a cross section view of an embodiment of a system for measuring the position of a movable element in a container; 
         FIG. 5  shows a cross section view of another embodiment of a system for measuring the position of a movable element in a container; and 
         FIG. 6  shows a cross section view of an embodiment of a system for measuring the position of a movable element in the container shown in  FIG. 4 . 
     
    
    
     DETAILED DESCRIPTION 
     The following 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 below may be employed separately or in any suitable combination to produce the desired results. In addition, one skilled in the art will understand that the following 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 following 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. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness. 
     In the following 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. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices, components, and connections. In addition, as used herein, 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. For instance, an axial distance refers to a distance measured along or parallel to the central axis, and a radial distance means a distance measured perpendicular to the central axis. 
     Referring now to  FIG. 1 , an embodiment of an offshore system  10  for drilling and/or producing a wellbore  11  is shown. In this embodiment, the system  10  includes an offshore vessel or platform  20  at the sea surface  12  and a subsea BOP stack assembly  100  mounted to a wellhead  30  at the sea floor  13 . The platform  20  is equipped with a derrick  21  that supports a hoist (not shown). A tubular drilling riser  14  extends from the platform  20  to the BOP stack assembly  100 . The riser  14  returns drilling fluid or mud to the platform  20  during drilling operations. One or more hydraulic conduits  15  extend along the outside of the riser  14  from the platform  20  to the BOP stack assembly  100 . The one or more hydraulic conduits  15  supply pressurized hydraulic fluid to the assembly  100 . Casing  31  extends from the wellhead  30  into the subterranean wellbore  11 . 
     Downhole operations are carried out by a tubular string  16  (e.g., drillstring, tubing string, coiled tubing, etc.) that is supported by the derrick  21  and extends from the platform  20  through the riser  14 , through the BOP stack assembly  100  and into the wellbore  11 . A downhole tool  17  is connected to the lower end of the tubular string  16 . In general, the downhole tool  17  may comprise any suitable downhole tools for drilling, completing, evaluating and/or producing the wellbore  11  including, without limitation, drill bits, packers, cementing tools, casing or tubing running tools, testing equipment, perforating guns, and the like. During downhole operations, the string  16 , and hence the tool  17  coupled thereto, may move axially, radially and/or rotationally relative to the riser  14  and the BOP stack assembly  100 . 
     Referring now to  FIGS. 1-3 , the BOP stack assembly  100  is mounted to the wellhead  30  and is designed and configured to control and seal the wellbore  11 , thereby containing the hydrocarbon fluids (i.e., liquids and gases) therein. In this embodiment, the BOP stack assembly  100  comprises a lower marine riser package (LMRP)  110  and a BOP or BOP stack  120 . 
     The BOP stack  120  is releasably secured to the wellhead  30  as well as the LMRP  110  and the LMRP  110  is releasably secured to the BOP stack  120  and the riser  14 . In this embodiment, the connections between the wellhead  30 , the BOP stack  120  and the LMRP  110  include hydraulically actuated, mechanical wellhead-type connections  50 . In general, the connections  50  may comprise any suitable releasable wellhead-type mechanical connection such as the DWHC or HC profile subsea wellhead system available from Cameron® International Corporation of Houston, Tex., or any other such wellhead profile available from several subsea wellhead manufacturers. Typically, such hydraulically actuated, mechanical wellhead-type connections (e.g., the connections  50 ) include an upward-facing male connector or “hub” that is received by and releasably engages a downward-facing mating female connector or receptacle  50   b . In this embodiment, the connection between LMRP  110  and the riser  14  is a flange connection that is not remotely controlled, whereas the connections  50  may be remotely, hydraulically controlled. 
     Referring still to  FIGS. 1-3 , the LMRP  110  includes a riser flex joint  111 , a riser adapter  112 , an annular BOP  113  and a pair of redundant control units or pods  114 . A flow bore  115  extends through the LMRP  110  from the riser  14  at the upper end of the LMRP  110  to the connection  50  at the lower end of the LMRP  110 . The riser adapter  112  extends upward from the flex joint  111  and is coupled to the lower end of the riser  14 . The flex joint  111  allows the riser adapter  112  and the riser  14  connected thereto to deflect angularly relative to the LMRP  110  while wellbore fluids flow from the wellbore  11  through the BOP stack assembly  100  into the riser  14 . The annular BOP  113  comprises an annular elastomeric sealing element that is mechanically squeezed radially inward to seal on a tubular extending through the LMRP  110  (e.g., the string  16 , casing, drillpipe, drill collar, etc.) or seal off the flow bore  115 . Thus, the annular BOP  113  has the ability to seal on a variety of pipe sizes and/or profiles, as well as perform a complete shut-off (“CSO”) to seal the flow bore  115  when no tubular is extending therethrough. 
     In this embodiment, the BOP stack  120  comprises an annular BOP  113  as previously described, choke/kill valves  131  and choke/kill lines  132 . The choke/kill line connections  130  connect the female choke/kill connectors of the LMRP  110  with the male choke/kill adapters of the BOP stack  120 , thereby placing the choke/kill connectors of the LMRP  110  in fluid communication with the choke lines  132  of the BOP stack  120 . A main bore  125  extends through the BOP stack  120 . In addition, the BOP stack  120  includes a plurality of axially stacked ram BOPs  121 . Each ram BOP  121  includes a pair of opposed rams and a pair of actuators  126  that actuate and drive the matching rams. In the illustrated embodiment, the BOP stack  120  includes four ram BOPs  121 —an upper ram BOP  121  including opposed blind shear rams or blades  121   a  for severing the tubular string  16  and sealing off the wellbore  11  from the riser  14 , and the three lower ram BOPs  121  including the opposed pipe rams  121   c  for engaging the string  16  and sealing the annulus around the tubular string  16 . In other embodiments, the BOP stack  120  may include a different number of rams, different types of rams, one or more annular BOPs or combinations thereof. As will be described in more detail below, the control pods  114  operate the valves  131 , the ram BOPs  121  and the annular BOPs  113  of the LMRP  110  and the BOP stack  120 . 
     The opposed rams  121   a, c  are located in cavities that intersect the main bore  125  and support the rams  121   a, c  as they move into and out of the main bore  125 . Each set of rams  121   a, c  is actuated and transitioned between an open position and a closed position by matching actuators  126 . In particular, each actuator  126  hydraulically moves a piston within a cylinder to move a connecting rod coupled to one ram  121   a, c . In the open positions, the rams  121   a, c  are radially withdrawn from the main bore  125 . However, in the closed positions, the rams  121   a, c  are radially advanced into the main bore  125  to close off and seal the main bore  125  and/or the annulus around the tubular string  16 . The main bore  125  is substantially coaxially aligned with the flow bore  115  of the LMRP  110 , and is in fluid communication with the flow bore  115  when the rams  121   a, c  are open. 
     As shown in  FIG. 3 , the BOP stack  120  also includes a set or bank  127  of hydraulic accumulators  127   a  mounted on the BOP stack  120 . While the primary hydraulic pressure supply is provided by the hydraulic conduits  15  extending along the riser  14 , the accumulator bank  127  may be used to support operation of the rams  121   a, c  (i.e., supply hydraulic pressure to the actuators  126  that drive the rams  121   a, c  of the stack  120 ), the choke/kill valves  131 , the connector  50   b  of the BOP stack  120  and the choke/kill connectors  130  of the BOP stack  120 . As will be explained in more detail below, the accumulator bank  127  may serve as a backup means to provide hydraulic power to operate the rams  121   a, c , the valves  131 , the connector  50   b , and the connectors  130  of the BOP stack  120 . 
     Although the control pods  114  may be used to operate the BOPs  121  and the choke/kill valves  131  of the BOP stack  120  in this embodiment, in other embodiments, the BOPs  121  and the choke/kill valves  131  may also be operated by one or more subsea remotely operated vehicles (“ROVs”). 
     As previously described, in this embodiment, the BOP stack  120  includes one annular BOP  113  and four sets of rams (one set of shear rams  121   a , and three sets of pipe rams  121   c ). However, in other embodiments, the BOP stack  120  may include different numbers of rams, different types of rams, different numbers of annular BOPs (e.g., annular BOP  113 ) or combinations thereof. Further, although the LMRP  110  is shown and described as including one annular BOP  113 , in other embodiments, the LMRP (e.g., LMRP  110 ) may include a different number of annular BOPs (e.g., two sets of annular BOPs  113 ). Further, although the BOP stack  120  may be referred to as a “stack” because it contains a plurality of ram BOPs  121  in this embodiment, in other embodiments, BOP  120  may include only one ram BOP  121 . 
     Both the LMRP  110  and the BOP stack  120  comprise re-entry and alignment systems  140  that allow the LMRP  110 -BOP stack  120  connections to be made subsea with all the auxiliary connections (i.e., control units, choke/kill lines) aligned. The choke/kill line connectors  130  interconnect the choke/kill lines  132  and the choke/kill valves  131  on the BOP stack  120  to the choke/kill lines  133  on the riser adapter  112 . Thus, in this embodiment, the choke/kill valves  131  of the BOP stack  120  are in fluid communication with the choke/kill lines  133  on the riser adapter  112  via the connectors  130 . However, the alignment systems  140  are not always necessary and need not be included. 
     As shown in  FIGS. 3-6 , the subsea BOP stack assembly  100  further includes a measurement system  200 , which includes at least one container. It should be appreciated by those of skill in the art that the containers may be any type of container with an internal volume and an element movable within the internal volume (e.g., piston or bellows type accumulators). In the embodiments illustrated in  FIGS. 3-6 , the containers are hydraulic accumulators  127   a  that include an element  401  movable within their internal volume, or cavity,  402 . The hydraulic accumulator  127   a  body is composed of an outer layer and an inner layer. The outer layer  409  of the accumulators  127   a  may include a metal, metal alloy and/or composite material (e.g., carbon fiber reinforced plastic). Composite materials are lighter than steel counterparts and possess high strength and stiffness, providing high performance in deep water, high pressure applications. The inner layer  410  of the accumulators  127   a  may include a metal and/or metal alloy. 
     In the embodiment in  FIG. 4 , the movable element  401  is a piston separating a hydraulic fluid  403  from a gas  404  stored in the internal volumes of the accumulators  127   a . It should be appreciated by those of ordinary skill in the art that the movable element could be any device movable in an internal volume of a container that is capable of separating fluids. The piston  401  may include a metal, metal alloy, plastic, or rubber. The surface area of the piston  401  includes a conductive surface area, including a conductive material, such as for example a metal (e.g., copper). The conductive surface area of the piston  401  can constitute the entire surface area of the piston, discrete surface areas of the piston, or any portion therebetween. 
     Referring again to  FIG. 4 , rubbing strips  405  are disposed along the interior of the accumulator  127   a  in an arrangement parallel to the longitudinal axis  406  of the accumulator  127   a . In this and other embodiments, the rubbing strips  405  are generally disposed in the interior of the accumulators  127   a  in the direction of the movement of the movable element/piston  401 . In one embodiment, the rubbing strips  405  are formed of a non-metallic polymer with a low coefficient of friction (e.g., μ s &lt;1.0), such as polytetrafluoroethylene. The rubbing strips  405  provide low-friction surfaces, resistant to wear and corrosion, upon which the piston  401  is movable within the accumulator  127   a.    
     In the embodiment shown in  FIG. 4 , one conductive strip  407  is disposed along the length of each rubbing strip  405  within the accumulator  127   a . As illustrated in  FIG. 6 , the conductive strips  407  are embedded in or otherwise attached to the rubbing strips  405 . Each conductive strip  407  extends beyond the profile of its associated rubbing strip  405 , so as to be capable of coming into contact with the conductive surface area(s) of the piston  401  as the piston  401  travels within the accumulator  127   a . In another embodiment, the conductive strips  407  can be placed on top of the rubbing strips  405  rather than being embedded in the rubbing strips  405 . 
     One end of each conductive strip  407  terminates, for example, at an end cap  408  of the accumulator  127   a . The end cap  408  includes typical openings and porting for communicating fluids (e.g., gas and/or liquid) to the accumulator  127   a  which do not constitute part of the invention and are therefore not shown or described in detail. The other end of each conductive strip  407  is connected to a power source  411 . The conductive strip  407  connects to the voltage/current source through a connector, such as a bulkhead connector, not shown. When the conductive surface area of the piston  401  is in contact with the conductive strips  407 , a circuit is formed with electrical characteristics (e.g., voltage, current, resistance) that vary as the piston moves along the length of the accumulator  127   a.    
     The length of the circuit formed between the piston  401  and conductive strips  407  decreases as the piston  401  moves through the interior of the accumulator  127   a  toward the power source  411 . Where one or more electrical characteristics are held constant, the other electrical characteristics of the circuit will vary as the length of the circuit varies. For instance, in general, where the voltage applied to the circuit is held constant, the current will increase and the resistance across the circuit will decrease as the length of the circuit decreases. Precise relationships between electrical characteristics will depend on a variety of factors, including the arrangement of the circuit and the materials of construction. 
     The location of the piston  401  can be determined based on measuring changes in the electrical characteristics because the electrical characteristics vary as the piston  401  moves along the length of the accumulator  127   a . Electrical characteristics may be measured from the circuit by any device commonly understood in the art to measure such characteristics, such as a current and/or voltage sensor. 
     Referring now to  FIG. 5 , the rubbing strips  505  are disposed along the interior of the accumulator  127   a  in an arrangement parallel to the longitudinal axis of the accumulator  127   a , similar to the arrangement in  FIG. 4 . In this embodiment, the rubbing strips  505  are formed of a non-metallic polymer with a low coefficient of friction (e.g., μ s &lt;1.0), such as polytetrafluoroethylene. The rubbing strips  505  provide low-friction surfaces, resistant to wear and corrosion, upon which the piston  501  is movable within the accumulator  127   a.    
     In the embodiment shown in  FIG. 5 , pairs of conductive strips  507  are disposed along the length of each rubbing strip  505  within the accumulator  127   a . The pairs of conductive strips  507  are embedded in the rubbing strips  505 . The pairs of conductive strips  507  extend beyond the profile of the rubbing strips  505 , so as to be capable of coming into contact with the conductive surface area(s) of the piston  501  as it travels within the accumulator  127   a . In another embodiment, pairs of conductive strips  507  can be placed on top of the rubbing strips  505  rather than being embedded in the rubbing strips  505 . Disposing pairs of conductive strips  507  in each rubbing strip  505  provides for a circuit between the conductive surface area of the piston  501  and the pair of conductive strips  507  in/on each rubbing strip  505 . This arrangement provides for redundancy (e.g., multiple circuits generating electrical characteristics which can be monitored to determine piston location) and enhances the accuracy of the measurement system by allowing for comparison of electrical characteristics of numerous circuits. It should also be appreciated that a pair of conductive strips  507  may also be disposed along or embedded within one rubbing strip  505 . 
     One end of each conductive strip  507  may terminate at an end cap  508  of the accumulator  127   a . The end cap  508  includes typical openings and porting for communicating fluids (e.g., gas and/or liquid) to the accumulator  127   a  which do not constitute part of the invention and are therefore not shown or described in detail. The other end of each conductive strip  507  is connected to a voltage/current source  511 . The conductive strip  507  connects to the voltage/current source through a connector, such as a bulkhead connector, which does not constitute part of the invention and is therefore not shown or described in detail. When the conductive surface area of the piston  501  is in contract with the conductive strips  507 , a circuit is formed which possesses electrical characteristics (e.g., voltage, current, resistance) that vary as the piston moves along the length of the accumulator  127   a . As discussed above, the location of the piston  501  can be determined based on the electrical characteristics readings from the circuit because the electrical characteristics vary as the piston  501  moves along the length of the accumulator  127   a . Electrical characteristic readings may be taken from the circuit by any device commonly understood in the art to detect such readings, such as a current and/or voltage sensor. 
     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.

Summary:
A system for determining the location of a piston within an accumulator is provided in which a short circuit is created between elements in the accumulator and the piston which is movable within the accumulator. As the piston moves along the longitudinal axis of the accumulator, the circuit&#39;s electrical characteristics (e.g., voltage, resistance, current) vary in accordance with the length of the circuit. Measurement of these electrical characteristics allows for precise determination of the piston location relative to the accumulator. In a commercial embodiment, the invention can be utilized to determine fluid volumes in an accumulator by monitoring the location of the piston. This invention overcomes prior art systems because, inter alia, it does not require electrical sensory equipment, enables remote monitoring, maintains system integrity and functions irrespective of container wall thickness.