Patent Publication Number: US-9896911-B2

Title: Subsea pressure protection system

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims priority to U.S. provisional patent application Ser. No. 62/287,174, filed on Jan. 26, 2016 and entitled “Subsea Pressure Protection System,” the content of which is incorporated herein by reference. 
    
    
     BACKGROUND 
     This disclosure relates generally to methods and apparatus for controlling pressure during hydrocarbon production. More specifically, this disclosure relates to methods and apparatus for preventing over-pressurization of equipment during hydrocarbon production. 
     As hydrocarbon reservoirs of increasingly high pressures are explored and developed, there are increasing demands to improve safety by providing increased control of high pressure fluids. To this end, high integrity pressure protection systems (HIPPS) have been employed in the oil and gas industry to provide a barrier between equipment designed to contain high pressure and equipment that is not capable of containing high pressure. HIPPS conventionally include one or more valves that are actuated by a control system that monitors pressure immediately upstream or downstream of the valves. When the control system senses an excessive pressure, the valves are closed as quickly as possible. 
     In certain subsea installations partially located on the sea floor, several wellheads, topped with wet trees, are fluidly connected to a single production manifold. The production manifold is in turn fluidly connected to a platform located on the sea surface via a flowline and a riser. The riser, is usually fluidly connected to a flare, a boarding and shut down valve (BSDV), a choke, among other components of a platform receiving system. The wellheads, the wet trees, and sometimes the production manifold coupled thereto, are designed to contain high pressure. But the flowline that couples the production manifold to the riser is rated to a pressure that is lower than the wellheads, but still higher than the flowing pressure. The pressure rating of the flowline is sometimes referred to as derated. A subsea HIPPS, also rated to high pressure, may be employed between the wellheads and the subsea manifold. The HIPPS actuates so as to automatically shut off any flow from the wellheads in response to excessive pressure. Thus the HIPPS contains excessive pressure, avoiding damaging the flowline or other equipment that is not capable of containing high pressure. 
     To accommodate the time that it will take to close the valves, subsea HIPPS often include a length of “high pressure” flowline designed to contain the increased pressure occurring downstream of the HIPPS until the valves can be closed. The zone equipped with high pressure flowline is referred to as the fortified zone. The length of the high pressure flowline needed and/or the size of the fortified zone are dependent on the operating speed of the HIPPS as well as the expected flow conditions. In certain applications, the length of the high pressure flowline may be several hundred and even several thousand feet long. Accommodating such length of high pressure flowline makes installation of subsea equipment challenging, in particular because of the large, and variable distances between the wellheads and the production manifold that are needed to dispose the required length of high pressure flowline. Also, retrofitting a subsea HIPPS to an existing facility without modifying its layout is usually not feasible. 
     Thus, there is a continuing need in the art for methods and apparatus for providing increased safety and containment of high pressure in hydrocarbon exploration and production. 
     BRIEF SUMMARY OF THE DISCLOSURE 
     A subsea pressure protection system coupled to a wet tree located on a sea floor comprises a high integrity pressure protection system including a pressure sensor, a plurality of valves, and a logic controller communicatively coupled to the pressure sensor and operable to close one or more of the plurality of valves upon sensing a pressure above a preset level. The subsea protection system further comprises a pipe bundle fluidly connected downstream of at least one of the plurality of valves. The pipe bundle comprises one or more coiled sections. 
     In some embodiments, the high integrity pressure protection system is removably coupled to a skid located on the sea floor. The pipe bundle may also be removably coupled to a skid. One of the plurality of valves may be fluidly connected downstream of the pipe bundle. The one or more coiled sections forming the pipe bundle are preferably terminated by high strength mechanical connectors which are not assembled by welding. 
     In another aspect, a subsea production system comprises at least one wet tree topping one well head located on a sea floor, a production manifold located on the sea floor, and a subsea protection system coupled between the at least one wet tree and the production manifold. The subsea protection system includes a pressure sensor, a plurality of valves, a logic controller communicatively coupled to the pressure sensor and operable to close one or more of the plurality of valves upon sensing a pressure above a preset level, and a first pipe bundle fluidly connected downstream of at least one of the plurality of valves and having one or more coiled sections. The subsea production system further comprises a platform receiving system coupled to the production manifold via a riser. 
     In some embodiments, the subsea protection system may be removably coupled to a skid located on the sea floor. The subsea production system may further comprise a second pipe bundle located on the platform receiving system. The second pipe bundle may be fluidly coupled to the riser. The subsea production system may further comprise a choke located on the platform receiving system. The second pipe bundle may be connected upstream of the choke. One of the plurality of valves may be fluidly connected downstream of the first pipe bundle. 
     A method of protecting equipment in a zone rated at low pressure against high pressure surges involves coupling a subsea protection system between at least one wet tree and a production manifold. The subsea protection system includes a pressure sensor, a plurality of valves, a logic controller communicatively coupled to the pressure sensor, and a first pipe bundle fluidly connected downstream of at least one of the plurality of valves and having one or more coiled sections. The method further involves operating the logic controller to close one or more of the plurality of valves upon sensing a pressure above a preset level. The method still further involves dissipating the high pressure surges in the first pipe bundle and upstream of the production manifold. 
     In some embodiments, one of the plurality of valves may be fluidly connected downstream of the first pipe bundle. The method may further involve operating the logic controller to close the one or more of the plurality of valves fluidly connected downstream of the first pipe bundle. The method may further involve coupling a second pipe bundle to a riser and upstream of a boarding and shut down valve located on a platform receiving system. The method may further involve closing the boarding and shut down valve. Coupling the subsea protection system between the at least one wet tree and the production manifold may be performed with a crane in a single lift. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a more detailed description of the embodiments of the present disclosure, reference will now be made to the accompanying drawings, wherein: 
         FIG. 1  is a schematic view of a subsea production field including an embodiment of a subsea pressure protection system. 
         FIG. 2  is a schematic view of a portion of the subsea pressure protection system shown in  FIG. 1  and including a high integrity pressure protection system (HIPPS). 
         FIG. 3  is a schematic view of another portion of the subsea pressure protection system shown in  FIG. 1  and including a pipe bundle. 
         FIG. 4  is a schematic view of a subsea production field including another embodiment of a subsea pressure protection system. 
         FIG. 5  is a schematic view of a portion of the subsea pressure protection system shown in  FIG. 4 . 
         FIG. 6  is a schematic view of a subsea production field including yet another embodiment of a subsea pressure protection system. 
     
    
    
     DETAILED DESCRIPTION 
     It is to be understood that the following disclosure describes several exemplary embodiments for implementing different features, structures, or functions of the invention. Exemplary embodiments of components, arrangements, and configurations are described below to simplify the present disclosure; however, these exemplary embodiments are provided merely as examples and are not intended to limit the scope of the invention. Additionally, the present disclosure may repeat reference numerals and/or letters in the various exemplary embodiments and across the Figures provided herein. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various exemplary embodiments and/or configurations discussed in the various figures. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact. Finally, the exemplary embodiments presented below may be combined in any combination of ways, i.e., any element from one exemplary embodiment may be used in any other exemplary embodiment, without departing from the scope of the disclosure. 
     Additionally, certain terms are used throughout the following description and claims to refer to particular components. As one skilled in the art will appreciate, various entities may refer to the same component by different names, and as such, the naming convention for the elements described herein is not intended to limit the scope of the invention, unless otherwise specifically defined herein. Further, the naming convention used herein is not intended to distinguish between components that differ in name but not function. Additionally, 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.” All numerical values in this disclosure may be exact or approximate values unless otherwise specifically stated. Accordingly, various embodiments of the disclosure may deviate from the numbers, values, and ranges disclosed herein without departing from the intended scope. Furthermore, as it is used in the claims or specification, the term “or” is intended to encompass both exclusive and inclusive cases, i.e., “A or B” is intended to be synonymous with “at least one of A and B,” unless otherwise expressly specified herein. 
     Referring initially to  FIG. 1 , a subsea production field comprises a wellhead  12 , topped with a wet tree  14 , and a production manifold  34 . The wellhead  12 , the wet tree  14 , and the production manifold  34  are located on a sea bed. While only one wellhead  12  and one wet tree  14  are shown connected to the production manifold  34  in  FIG. 1 , several wellheads and wet trees are usually fluidly connected to the same production manifold. The production manifold  34  may be fluidly connected to a platform receiving system  42  via a flowline  36  and a riser  40 . The platform receiving system  42  may include pressure and flow control components, such as a BSDV or choke, as further discussed hereinafter. 
     The subsea production field comprises a subsea fortified zone  30  that includes equipment designed to contain high pressure. For example, the type of material making the pipes, and the type of connection between the pipes are selected to contain high pressure fluids (e.g., fluids at pressure in excess of 15,000 psi), even if such pressure levels are not expected during normal production conditions and may only occur in exceptional circumstances. 
     In many circumstances it would be economically or physically impractical to extend the subsea fortified zone  30  the entire distance from the wellhead  12  to the platform receiving system  42 . Accordingly, the subsea production field also comprises a zone  38  rated at lower pressure that includes equipment that is not capable of containing high pressure. For example, the type of material making the pipes, and the type of connection between the pipes may be less expensive, lighter weight, and easier to assemble than the type of material making the pipes and connections between the pipes in the subsea fortified zone  30 . In the example shown in  FIG. 1 , the zone  38  that is rated at lower pressure comprises the production manifold  34 , and the flowline  36 . 
     An embodiment of a subsea pressure protection system  100  is provided in the subsea fortified zone  30 . The subsea pressure protection system  100  comprises a HIPPS  22  and a pipe bundle  28 . As will become apparent, by selecting an appropriate length of the pipe bundle  28 , the location of the separation between the subsea fortified zone  30  and the zone  38  rated at lower pressure may be kept fixed at the outlet of the pipe bundle  28 . 
     In the example shown in  FIG. 1 , the HIPPS  22  and the pipe bundle  28  are removably mounted on skids  18  and  24 , respectively. However the pipe bundle  28  may, in other examples, be fixedly mounted. The skids  18  and  24  may be made of a steel frame on which equipment (e.g., the HIPPS  22  or the pipe bundle  28 ) is mounted to facilitate handling and installation of such equipment. The skids  18  and  24  may comprise bases  20  and  26 , respectively, which are fluidly connected to other elements of the subsea production field by jumpers, such as jumpers  16   a  and  16   b , that are designed to contain high pressure, or jumper  32 , that may not be capable of containing high pressure. In other examples, the HIPPS  22  and the pipe bundle  28  may not be mounted on skids. 
     The installation or removal of the subsea pressure protection system  100  is facilitated by its compactness. The jumpers  16   b  and  32  may typically span over a length of approximately 100 feet, and thus the HIPPS  22  and the production manifold may be located within a distance of approximately 200 feet. It should be noted however that jumpers may span over shorter or longer lengths, so that the resulting distance between the HIPPS  22  and the manifold may significantly differ from 200 feet. Further, the pipe bundle  28  that is mounted on the skid  24  may be installed with a crane in a single lift, regardless of the length of the pipe bundle  28 . Still further, the location of the production manifold  34  relative to the wellhead  12  (and the other wellheads to which the manifold may be connected) may be independent of the variable length of the pipe bundle  28 . 
     Turning now to  FIG. 2 , the HIPPS  22  includes valves  102 , logic controller  106 , and pressure sensors  108 . Valves  102  are connected in series between inlet  110  coupled to the wet tree  14  (in  FIG. 1 ), and outlet  112  coupled to the production manifold  34  (in  FIG. 1 ). The valves  102  may be high-pressure gate valves, or some other type of valve, that can shut off flow through the subsea pressure protection system  100  and are rated to handle high pressure that may escape from the wet tree  14 . Pressure sensors  108  are disposed upstream and optionally downstream of valves  102 , and are operable to measure the pressure within the pressure protection system  100 . Pressure sensors  108  are operably coupled to the logic controller  106 . The logic controller  106  is programmed to monitor the pressure measured by pressure sensors  108 . If the pressure measured by pressure sensors  108  exceeds a preset level (e.g., the pressure rating of zone  38 ), the logic controller  106  sends a signal that closes one or more valves  102 . Once the one or more valves  102  are closed, the production manifold  34  is isolated from the wet tree  14 . 
     Turning now to  FIG. 3 , the pipe bundle  28  comprises a length of continuous pipe or tubing  104  that is connected between inlet  114  coupled to HIPPS  22  (in  FIG. 1 ), and outlet  116  coupled to production manifold  34  (in  FIG. 1 ). The pipe or tubing  104  may be made of high strength steel or other alloy that is rated to handle the high pressure that may escape from the wet tree  14 , and has a length sufficient to contain an increased pressure in the pipe or tubing  104  until the valves  102  can be closed. 
     Two or more portions of the pipe or tubing  104  overlap or are doubled, such as by coiling, looping, folding or wrapping. The pipe bundle  28  is formed by bending the pipe, and is preferably not but may also be formed by connecting preformed coiled sections terminated by high strength mechanical connections, some of which being preformed with a curved shape, or by a combination of both bending and assembling. To maintain high pressure rating of the pipe bundle, the pipe sections are preferably not welded. In any case, the pipe bundle  28  is more compact than a straight pipe having the same length as the pipe bundle  28 . In certain embodiments, the pipe bundle  28  may comprise a length of pipe or tubing that has been rolled into a substantially cylindrical coil, a substantially oval coil, a spiral coil, a coil made of a stack of spirals, or a coil having another shape. 
     In operation, one or more of the pressure sensors  108  may continuously monitor the pressure of the fluid flowing from the wet tree  14 . The pressure sensors  108  are communicatively coupled to the logic controller  106 . Upon sensing a pressure above a preset level, the logic controller  106  closes one or more valves  102 . When the one or more valves  102  are closed, the overpressure may have entered the pipe bundle  28 , but it starts dissipating upon closure of the one or more valves  102 . The pipe bundle  28  is long enough so that the overpressure has dissipated at the outlet of the pipe bundle  28 , and the pressure does not exceed the pressure rating in the zone  38 . 
     Turning to  FIG. 4 , another embodiment of the subsea pressure protection system  100  is provided in the subsea fortified zone  30 . The subsea pressure protection system  100  comprises a HIPPS  22  removably mounted on a spool base  44  of a skid  46 , and a pipe bundle integrated in the spool base  44 . In this embodiment, the HIPPS  22  and the production manifold  34  may be located within a distance of approximately 100 feet. Further, the HIPPS  22  and the pipe bundle are provided on the same skid  46 . Thus, valves that are driven by the same logic controller may be disposed upstream and downstream of the pipe bundle, as illustrated in  FIG. 5 . 
     Turning to  FIG. 5 , a valve  102 ′ that is coupled downstream of the spool base  44  may be provided in the HIPPS  22  adjacent the separation between the subsea fortified zone  30  and the zone  38  rated at lower pressure. The valve  102 ′ is preferably driven by the logic controller  106  that also drives the valves  102  that are fluidly coupled upstream of the spool base  44 . The valve  102 ′ may be provided by adding another valve or relocate one of the valves  102  to a position that is downstream of the spool base  44 . 
     In operation, valve  102 ′ may also be operated by the logic controller  106  and be closed upon one of the pressure sensors  108  sensing a pressure above a preset level. The valve  102 ′ may provide an additional barrier between equipment designed to contain high pressure and equipment that is not capable of containing high pressure. 
     Turning now to  FIG. 6 , to accommodate transient overpressure occurring on the platform receiving system  42 , for example upstream of a choke  56 , a riser  40  rated at higher pressures, and pipe sections also rated at higher pressures, welded between the riser  40  and the BSDV  54 , or between the BSDV  54  and the choke  56  may be needed. As such, subsea HIPPS  22  may not completely eliminate the need of equipment designed to contain high pressure downstream of the production manifold  34 . 
     In yet another embodiment of the subsea pressure protection system  100  shown in  FIG. 6 , a pipe bundle  50  is provided on the platform receiving system  42  upstream of the choke  56 . The pipe bundle  50  may be rated at a shut-in pressure that is higher than the flowing pressure. In the example of  FIG. 6 , the pipe bundle  50  is coupled between the riser  40  and the BSDV  54 , however, the pipe bundle  50  may be coupled elsewhere between the riser  40  and the choke  56 . In any case, the pipe bundle  50  provides an extended length of pipe in a zone  52  rated at shut-in pressure. 
     While the disclosure is susceptible to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings and description. It should be understood, however, that the drawings and detailed description thereto are not intended to limit the disclosure to the particular form disclosed, but on the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the present disclosure.