Abstract:
A system and method for reducing fluid pressure in a pipe connecting a well to a remote location, according to which a section of tubing is inserted into the pipe to define a space between the tubing and the pipe. Pressurized fluid is introduced into the pipe in a manner to displace the fluid in the pipe and reduce the fluid pressure in the pipe to prevent the formation of hydrates in the pipe.

Description:
BACKGROUND  
       [0001]     In subsea petroleum recovery operations, pipeline systems are used to transport unprocessed and untreated petroleum production fluids from a petroleum reservoir in the sea bed to a production facility, or the like, floating on the surface of the sea.  
         [0002]     If the production fluid, which usually includes water and gas, is not maintained above a threshold temperature, hydrates, wax and/or other types of compounds (hereinafter collectively referred to as “hydrates”) will form which can cause blockage of the pipeline. Although the fluids come from the reservoir at a relatively high temperature, they will cool down when flowing through the subsea pipeline and especially when they sit in the pipeline when the flow terminates. In either case, the fluids can cool down below the above threshold temperature causing the hydrates to form.  
         [0003]     This problem is exacerbated due to the fact that there is a relatively high head of liquid and fluid pressure in the pipeline that increase the value of the above threshold temperature to a value that is often greater than the temperature of the fluid in the pipe, thus increasing the chances of causing formation and maintenance of the hydrates in the pipe.  
         [0004]     Therefore, what is needed is a cost-effective and efficient system and method for removing the hydrates from the pipeline.  
     
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0005]      FIG. 1  is an elevational view of a subsea petroleum operation including an embodiment of the invention.  
         [0006]      FIG. 2  is an enlarged sectional view of a portion of the pipe of  FIG. 1 .  
         [0007]      FIGS. 3-6  are views, similar to that of  FIG. 2 , but depicting alternative embodiments. 
     
    
     DETAILED DESCRIPTION  
       [0008]     Referring to  FIG. 1 , the reference numeral  10  refers to a pipe that forms a riser and a flow line in a subsea petroleum recovery operation. The pipe  10  extends between a production facility  12  that floats on the surface of the sea S, and a tree system  14  extending just above a subsea well  16 . Although the pipe  10  is shown curved in a manner to form an arc, it is understood that this is for the purpose of example only and that it can take other forms.  
         [0009]     The tree system  14  is supported at the upper surface of the sea bed B and the well  16  extends into the sea bed for recovering petroleum based production fluid from a formation formed in the sea bed. The tree system  14  is conventional and, as such, includes a series of valves and associated components (not shown) for controlling the flow of the production fluid in the pipe  10 . Thus, the production fluid flows from the well  16 , through the tree system  14  and the pipe  10  and to the production facility  12  for further processing, under control of the tree system  14 .  
         [0010]     Although the production fluid from the well  16  is at a relatively high temperature, it will cool down when flowing through the pipe  10  and/or when it is confined in the pipe when the flow terminates. It will be assumed that the relatively high static head and fluid pressure in the pipe  10  causes the above threshold temperature, e.g., the temperature below which hydrates are formed, to be relatively high and that the temperature of the fluid falls below this threshold temperature therefore causing the hydrates to form in the pipe, as discussed above.  
         [0011]     To remove the hydrates from the pipe  10  according to an embodiment of the invention shown in  FIG. 2 , the normal flow of production fluid from the well  16  and into the pipe  10  is terminated by closing the proper valves in the tree system  14  ( FIG. 1 ), and a section of coiled tubing  18  is installed in the pipe  10 . In particular, the lower end of the tubing  18  is inserted into the pipe and lowered from a supply reel, or the like, at the production facility  12  until the latter end reaches a predetermined depth in the pipe, which corresponds to the depth sufficient to remove the head of liquid in the pipe, as will be explained. (Although the sections of the pipe  10  and the coiled tubing  18  are shown extending vertically in  FIG. 2 , this is for the purpose of illustration only since it is clear from  FIG. 1  that other sections of the pipe  10  and the coiled tubing extend at an angle to the vertical.) The lower end of the tubing  18  extending in the pipe  10  is open and receives production fluid under conditions to be described.  
         [0012]     An annular space  20  is formed between the outer diameter of the tubing  18  and the inner diameter of the corresponding section of the pipe, and continues to the production facility  12 . Thus, production fluid from the well  16  accumulates in the tubing  18  and in the space  20  and creates a static head and a relatively high fluid pressure.  
         [0013]     A supply of compressible, relatively low-density fluid, such as nitrogen or hydrocarbon gas, (hereinafter referred to as “gas”) from the production facility  12  is then introduced into the upper end of the space  20 . The gas passes through the space  20  in a direction as shown by the arrows A which is in a direction towards the well  16 , and is introduced at a pressure sufficient to displace the production fluid in the space.  
         [0014]     The displaced production fluid is forced into the end of the tubing  18  as shown by the arrows B, before passing through the tubing in a direction towards the production facility  12  shown by the arrows C. During this movement, the original production fluid in the tubing  18  is also displaced. By the time the gas flowing down the space  20  reaches the end of the tubing  18 , most of the production fluid is evacuated from the space  20  and the tubing  18  and passed to the production facility  12 . The gas will then start flowing up the space  20  and the tubing  18  and carry any remaining production fluid with it.  
         [0015]     Once most of the production fluid has been removed in the above manner, the supply of the gas to the space  20  is stopped, the system is depressurized either via the space and/or via the tubing  18 . Thus, the remaining production fluids will be allowed to expand and flow naturally to the production facility by a variety of physical phenomena including the expansion of the relatively low vapor pressure production fluid and/or the vaporization of the high vapor pressure gas.  
         [0016]     It can be appreciated that this evacuation of the production fluid from the space  20  and the tubing  18  significantly reduces the static head and fluid pressure in the space and the tubing. This lowers the temperature of the fluid in the pipe to a value below the above-mentioned threshold temperature, and thus causes melting of the hydrates by the heat in the fluid and the surroundings, and the elimination of any blockage in the pipe  10 .  
         [0017]     After the above operation is completed, the tubing  18  can be removed from the pipe  10 , and the normal flow of production fluid from the well  16 , through the pipe  10  and to the production facility  12 , can be restarted under control of the valves in the tree system  14 .  
         [0018]     The embodiment of  FIG. 3  contains several components of the embodiment of  FIG. 2 , which are given the same reference numerals. It will be assumed that the relatively high static head and fluid pressure in the pipe  10  causes the above threshold temperature, e.g., the temperature below which hydrates are formed, to be relatively high and that the temperature of the fluid falls below this threshold temperature therefore causing the hydrates to form in the pipe, as discussed above.  
         [0019]     To remove the hydrates from the pipe  10  according to the embodiment of  FIG. 3 , normal flow of production fluid from the well  16  and into the pipe  10  is terminated by closing the proper valves in the tree system  14 , and the coiled tubing  18  is installed in the pipe  10  in the manner discussed above. A packer  26  is inserted into the space  20  to a desired depth and then set in place to seal against production fluid flow across it in a conventional manner and therefore isolate that portion of the space  20  extending above the packer from that portion extending below, as viewed in  FIG. 3 . This insertion of the packer  26  can be done in any conventional manner including installing the packer  26  on the lower end portion of the tubing  18  before it is installed in the pipe  10 .  
         [0020]     In this embodiment, the tubing  18  is kept void of production fluid during the above insertion of the packer  26  by maintaining a gas pressure on the tubing or by the use of a special check valve (not shown) that can be controlled by pressure variations in the tubing.  
         [0021]     The gas in the tubing  18  is then vented to the production facility  12  ( FIG. 1 ) or the above check valve is opened, causing the production fluid below the packer  26  to expand and flow upwardly in the tubing and to the production facility. This creates a gas/liquid interface in the pipe  10  that most likely will be somewhere in the tubing  18 , with its position depending on the properties of the fluid, such as its vapor pressure and/or gas-to-liquid ratio.  
         [0022]     The static head and fluid pressure in the pipe  10  is determined according to this height of the gas/liquid interface and the pressure of the gas above the interface. With the tubing  18  and the packer  26  in place and the tubing  18  depressurized in accordance with the above, the interface is likely to be lower than the original head in the pipe  10  before the tubing  18  and the packer are introduced, and thus the final equilibrium pressure in the pipe  10  will be lower.  
         [0023]     The depth to which the tubing  18  and the packer  26  are inserted can be selected to ensure that the final equilibrium pressure is low enough to lower the temperature of the fluid in the pipe to a value below the above-mentioned threshold temperature, and thus cause melting of the hydrates by the heat in the fluid and the surroundings, and the elimination of any blockage in the pipe  10 . After the above operation is completed, the tubing  18  and the packer  26  can be removed from the pipe  10 , and the normal flow of production fluid from the well  16 , through the pipe  10  and to the production facility  12 , can be restarted.  
         [0024]     The embodiment of  FIG. 4  contains several components of the embodiment of  FIG. 3 , which are given the same reference numerals. According to the embodiment of  FIG. 4 , a submersible electric motor  30  is connected to the lower end of the tubing  18  and is operatively connected to a submersible pump  32 .  
         [0025]     It will be assumed that the relatively high static head and fluid pressure in the pipe  10  causes the above threshold temperature, e.g., the temperature below which hydrates are formed, to be relatively high and that the temperature of the fluid falls below this threshold temperature therefore causing the hydrates to form in the pipe, as discussed above.  
         [0026]     To remove the hydrates from the pipe  10  according to the embodiment of  FIG. 4 , the normal flow of production fluid from the well  16  and into the pipe  10  is terminated by closing the proper valves in the tree system  14 , and the coiled tubing  18  is installed in the pipe  10  in the manner discussed above.  
         [0027]     The motor  30  is activated to drive the pump  32  to lift the production fluid from that portion of the pipe  10  extending below the tubing  18 , and pass the fluid through the tubing  18  and the pipe  10  to the production facility  12  ( FIG. 1 ), as shown by the arrows A. Also, the pump  32  pumps the fluid from that portion of the space  20  extending below the packer  26 , through the tubing  18 , and to the production facility  12  ( FIG. 1 ), as shown by the arrows B. As production fluid is pumped from the pipe  10  and the space  20  in the above manner, the packer  26  prevents the production fluid in the space  20  above the packer from flowing downwardly. Thus, the static head and the fluid pressure in the pipe  10  will be quickly reduced and the temperature of the fluid is lowered to a value below the above-mentioned threshold temperature, thus causing melting of the hydrates by the heat in the fluid and the surroundings, and the elimination of any blockage in the pipe  10 . After the above operation is completed, the tubing  18 , the packer  26 , the pump  30  and the motor  32  can be removed from the pipe  10 , and the normal flow of production fluid from the well  16 , through the pipe  10  and to the production facility  12 , can be restarted.  
         [0028]     It is understood that the pump  30  and the motor  32  can be replaced by a hydraulic power turbine in which case separate conduits could be provided to convey the hydraulic production fluid supply, the hydraulic production fluid return and the fluid being removed from the pipe. Also, a length of flexible tubing could be installed on the suction end of the pump  30  to extend the reach of the production fluid removal capability of the system to some point significantly beyond the location of the pump. Also, the packer  26  can be eliminated and the fluid in the entire space  20  removed by the pump  32 .  
         [0029]     The embodiment of  FIG. 5  includes components of the previous embodiments, which are given the same reference numerals. To remove the hydrates from the pipe  10  according to the embodiment of  FIG. 5 , the normal flow of production fluid from the well  16  and into the pipe  10  is terminated by closing the proper valves in the tree system  14  ( FIG. 1 ), and two radially spaced, concentric coiled tubes  18   a  and  18   b  are installed in the pipe  10 . The lower ends of the tubes  18   a  and  18   b  are inserted into the pipe  10  and lowered from a supply reel, or the like, at the production facility  12  ( FIG. 1 ) until the latter ends reach a predetermined depth in the pipe, which corresponds to the depth sufficient to remove the head of liquid in the pipe. (Although the sections of the pipe  10  and the tubes  18   a  and  18   b  are shown extending vertically in  FIG. 5 , this is for the purpose of illustration only since it is clear from FIG. I that other sections of the pipe  10  and the coiled tubes extend at an angle to the vertical.) The lower end of the tubes  18   a  and  18   b  extending in the pipe  10  are open and receive production fluid under conditions to be described.  
         [0030]     As in the previous embodiments, a space  20  extends between the outer surface of the tube  18   b  and the inner surface of the pipe  10 . Also, a space  36  is formed between the outer surface of the tube  18   a  and the inner surface of the tube  18   b  and extends to the production facility  12 . Thus, production fluid from the well  16  accumulates in the tubes  18   a  and  18   b  and in the space  36  and creates a static head and a relatively high fluid pressure.  
         [0031]     A packer  26  is lowered into the space  20  to a desired depth and then set in place to seal against production fluid flow across it in a conventional manner and therefore isolate that portion of the space  20  extending above the packer from that portion extending below, as viewed in  FIG. 3 .  
         [0032]     A supply of compressible, relatively low-density fluid, such as nitrogen or hydrocarbon gas, (hereinafter referred to as “gas”) from the production facility  12  is then introduced into the upper end of the space  36 . The gas passes through the space  36  in a direction as shown by the arrows A which is in a direction towards the well  16 , and is introduced at a pressure sufficient to displace the production fluid in the space.  
         [0033]     The displaced production fluid is forced into the end of the tube  18 a as shown by the arrows B, before passing through the latter tube in a direction towards the production facility  12  shown by the arrows C. During this movement, the original production fluid in the tube  18 a is also displaced. By the time the gas flowing down the space  36  reaches the end of the tubes  18 a, most of the production fluid is evacuated from the space  36  and the tube  18   a  and passed to the production facility  12 . The gas will then start flowing up the space  36  and the tubes  18   a  and  18   b  and carry the production fluid with it.  
         [0034]     The cross section of the flow path through the space  36 , as well as the flow path defined in the interior of the tube  18   a , is significantly smaller than the diameter of the pipe  10 . This promotes the lifting of the production fluid up the tube  18   a  and the space  36  in accordance with the above.  
         [0035]     Once most of the fluid has been removed in the above manner, the supply of the gas to the space  36  is stopped, the system is depressurized either via the space or the tubing and the remaining production fluid allowed to expand and flow naturally to the production facility  12  via the tubes  18   a  and  18   b  by a variety of physical phenomena including the expansion of the relatively low vapor pressure production fluid and/or the vaporization of the high vapor pressure gas.  
         [0036]     It can be appreciated that this evacuation of the production fluid from the space  36  and the tubes  18   a  and  18   b  in the foregoing manner significantly reduces the static head and fluid pressure in the space and the tubing. The reduction of the static head and fluid pressure in the pipe  10  lowers the temperature of the fluid in the pipe to a value below the above-mentioned threshold temperature, and thus causes melting of the hydrates by the heat in the fluid and the surroundings, and the elimination of any blockage in the pipe  10 . After the above operation is completed, the tubes  18   a  and  18   b  and the packer  26  can be removed from the pipe  10 , and the normal flow of production fluid from the well  16 , through the pipe  10  and to the production facility  12 , can be restarted.  
         [0037]     The embodiment of  FIG. 6  contains several components of the embodiment of  FIG. 2 , which are given the same reference numerals, and, as in the previous embodiments, it will be assumed that production fluid is present in the tubing  18  and in the space  20  between the tubing  18  and the pipe  10 . It will be assumed that the relatively high static head and fluid pressure in the pipe  10  causes the above threshold temperature, e.g., the temperature below which hydrates are formed, to be relatively high and that the temperature of the fluid falls below this threshold temperature therefore causing the hydrates to form in the pipe, as discussed above.  
         [0038]     To remove the hydrates from the pipe  10  according to the embodiment of  FIG. 6 , the normal flow of production fluid from the well  16  and into the pipe  10  is terminated by closing the proper valves in the tree system  14 , and the tubing  18  is installed in the pipe  10  in the manner discussed above. One or more conventional pigging devices  40  are then inserted downwardly into the space  20  through the column of production fluid in the space. This insertion can be done in any conventional manner including installing the pigging devices  40  on the lower end portion of the tubing  18  before it is inserted in the pipe  10 .  
         [0039]     The pigging devices  40  are configured to normally allow fluids to flow past them in the space  20 , but can be expanded to bridge across the space  20  in a conventional manner, thus creating a dynamic seal. It will be assumed that the pigging device  40  nearest to the production facility  12  ( FIG. 1 ), which is the uppermost device as viewed in  FIG. 6 , is expanded and the remaining devices are configured to allow fluid to flow past them.  
         [0040]     Gas from the production facility  12  is then introduced into the upper end of the tubing  18  and flows in the tubing in a direction shown by the arrows A, which is towards the well  16 . The gas displaces the production fluid in the tubing  18  which exits the lower end of the tubing, and flows in the space  20  in a direction shown by the arrows C, which is towards the production facility  12 . Thus, the displaced fluid and the gas flowing through the space  20  in the above manner will pass through all of the pigging devices  40  with the exception of the above device nearest to the production facility which will be pushed upwardly in the space by the gas and fluid. As the latter pigging device  40  moves upwardly, it will sweep out the fluids above the space  20 . The remaining pigging devices  40  can be expanded as necessary and forced towards the production facility  12  in the above manner to remove the desired quantity of production fluid from the pipe.  
         [0041]     Once the production fluid has been removed from the space  20  in the above manner, the supply of the gas is stopped, the system is depressurized either via the space or by the tubing  18 . The remaining production fluid is allowed to expand and flow naturally to the production facility  12  via the tube  18  or by the space  20  by a variety of physical phenomena including the expansion of the relatively low vapor pressure production fluid and/or the vaporization of the high vapor pressure gas. After the level of production fluid is at or below the desired level, the pipe  10  can be further depressurized if desired by flowing the gas down the space  20  and upwardly through the tubing  18 .  
         [0042]     The reduction of the static head and fluid pressure in the pipe  10  lowers the temperature of the fluid in the pipe to a value below the above-mentioned threshold temperature, and thus causes melting of the hydrates by the heat in the fluid and the surroundings, and the elimination of any blockage in the pipe  10 . After the above operation is completed, the tube  18  and the pigging devices  40  are removed from the pipe  10 , and the normal flow of production fluid from the well  16 , through the pipe  10  and to the production facility  12 , is restarted.  
       Variations  
       [0043]     It is understood that variations may be made in the foregoing without departing from the scope of the invention. For example, although the pipe  10  and the tubing  18  are shown extending vertically in  FIGS. 2-6  for the purpose of example, it is understand that they also can extend at an angle to the vertical. Hence, spatial references, such as “up”, “down”, “upper”, “lower”, “upwardly”, “downwardly”, etc. are for the purpose of illustration only and do not limit the specific orientation or location of the pipe and tubing. Also, the general shape of the pipe extending between the facility  12  and the tree system  14  can vary from the form of the example of  FIG. 1 . Further, the above embodiments are not limited to the flowing of production fluid from a well, but are equally applicable to the flow of any type of fluid from a well to a remote location. Still further, the space  20  does not necessarily have to be annular.  
         [0044]     Although only a few exemplary embodiments of this invention have been described in detail above, those skilled in the art will readily appreciate that many other modifications are possible in the exemplary embodiments without materially departing from the novel teachings and advantages of this invention. Accordingly, all such modifications are intended to be included within the scope of this invention as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures.