Patent Publication Number: US-2011052418-A1

Title: System and method for a water cooling pump

Description:
FIELD OF INVENTION 
     The present invention relates to a system and method for a deep well pump. More specifically, the present invention relates to a system and method for a cooling apparatus in the deep well pump. The well pump may involve the pumping of any sort of fluid, e.g., oil, water, etc., and the cooling entity may be any sort of appropriate fluid, e.g., water, etc. 
     BACKGROUND 
     Current systems for deep well pumping involve electrical submersible pumps (“ESPs”) or geared centrifugal pumps (“GSPs”). Such pumps are the current, principal methods used as artificial lifts in high rate oil wells, where a multi-stage centrifugal pump is located downhole. For example, in an ESP system, a downhole electrical motor directly drives the pump, with electric power supplied to the motor via a cable extending from the surface to the motor&#39;s location downhole. For example, in a GSP system, the pump is driven via a rotating rod string extending from the surface to a speed increasing transmission system located downhole. The speed increasing transmission system is used to increase the relatively slow rotation of the rod string to a much faster rotation, as needed by the pump. In this example, the rod string is driven by an electric motor situated at the surface. 
     These current systems, used in the recovery of, e.g., fluids and/or quasi-fluids, experience undesired thermal effects. For example, the temperature of the produced fluid in thermally stimulated oil wells exceeds the operating temperature limits of ordinary downhole pumping systems. For low to moderate productivity wells, the GSP or sucker rod pumping system can be used, provided certain changes in the metallurgy of the downhole components are made. However, such rod pumping systems are incapable of handling highly productive wells. At present, an electric submersible pump (ESP) is the only practical option available. However, the high produced fluid temperatures are particularly severe for a pump system. Also, ESPs have a high voltage electric motor, as well as insulated cable downhole, exposed to temperatures that can exceed 500 degrees Fahrenheit. A mere change in the metallurgy does not cure the high temperature situation. Some systems have increased the operating limit of the downhole electrical components of the ESP system to about 400 degrees Fahrenheit. However, those high temperature systems are expensive and not highly reliable. Accordingly, there exists a need for a reliable, reasonable-cost high temperature system for high volume lift of fluid or quasi-fluid. 
     In  FIG. 1 , a normal temperature ESP system  100  is shown having a production pipe  101  connected to a wellhead  102 , which is essentially connected to a casing or housing  104  which surrounds and protects downhole elements the system  100 . Power  103  is fed to the system via a power cable  107  which runs inside the casing  104  to power the motor  111 , e.g., an electric motor. The motor  111  is located downhole in the system. The motor  111  drives the pump  108  above it. A motor protector  110  is connected between the motor  111  and the pump  108 . The motor protector  110  consists of seals and pressure compensators that work to keep fluid out of the motor  111 . The pump  108 , e.g., a multi-stage centrifugal pump which runs at ˜3500 RPM, is located directly above the motor  111  and motor protector  110 . At the lower end of the pump  108 , there is a pump intake section  109  which has pump vents or holes. The tubing  105  attaches to the top of the pump and forms the flow conduit for the pressurized well fluid to travel to the surface. Cable straps  106  are used to hold the tubing  105  and the power cable  107  inside the ESP well casing  104 . In operation, the motor  111  is supplied electric current via the power cable  107  that extends from the surface to the pump  108 . The motor  111  drives the pump  108  to lift well fluid out to the surface. At the surface, the well may be equipped with a wellhead having valves and piping to transmit the well fluid to a collection facility or other location. 
       FIG. 2  shows a more detailed view of the downhole components and the flow of fluid  200  according to the ESP system  100  of  FIG. 1 . The formation fluid enters the perforations in the casing  104  located below the motor  111 . This formation fluid flows toward the pump intake or inlet  109  via the annular space between the motor and the well casing. This well fluid flow cools the motor  111 , which is needed for the operation of the ESP system. Otherwise, the motor  111  would rapidly overheat and fail. After passing by and cooling the motor  111 , the well fluid flows into the pump inlet  109  and is pressurized by the multiple pump stages and then flows into the tubing at the outlet of the pump  108 . The pump  108  increases the pressure of the fluid to a level such that it can flow via the tubing  105  to the surface. 
     As shown in  FIG. 2 , cable straps  106  are used to hold the power cable  107 , which delivers power to the motor, in place with the pump  108  and motor protector  110 . 
     In  FIG. 3 , a normal temperature GCP system  300  is shown having a production pipe or flow line  303  essentially connected to a casing or housing  305  which surrounds and protects downhole elements of the system  300 . Inside the casing, typical elements such as a rod drive string  302  is run inside a tubing  301  to the GCP transmission assembly  304 . A pump  305  is located just below the GCP transmission assembly  304 , through which the tail end  306  of the tubing  301  is run. The fluid enters via openings in the casing  305  and are drawn into the tubing tail end  306 , and then pumped up to the surface via the tubing  301 . 
     Generally, for an electrical submersible pump to handle a high temperature or a very high temperature, significant modifications in the construction and materials used, e.g., in the motor and electrical cable, must be made. For example, the materials used in the seals and the bearings in the motor protector are specialized for high temperature service. The pressure compensators for balancing the pressure between the interior of the motor and the wellbore are made to have a much larger capacity in order to handle the large temperature variations, and are constructed of a high temperature material. Such modifications results in a much more expensive, less efficient, and possibly less reliable high temperature electrical submersible pump than a normal temperature electrical submersible pump. Presently, while the maximum operating temperature for such high temperature electrical submersible pumps is about 425° F., the recommended continuous operating temperature is significantly less. 
     Accordingly, a need exists for a system and method of a reliable, cost and time efficient electrical submersible pump which can handle high temperature situations. 
     The geared centrifugal pump (GCP), for example, as described in U.S. Pat. No. 5,573,063, is, like the ESP, a high volume deep well pumping apparatus. A schematic of a typical normal temperature installation is provided as  FIG. 3 . Since all downhole components of the GCP are purely mechanical and principally fabricated from steel alloy, the GCP is more easily adapted to very high temperature than an ESP. Nonetheless, temperatures greater than 500° F. tax the strength and durable of even high temperature steel alloys, and employing the cooling technique described above on a GCP would allow for a less expensive and more reliable pumping system that a conventionally configures GCP adapted to very high temperature operation. 
     As shown in  FIG. 3 , a normally configured GCP consists of a multi-stage centrifugal downhole pump driven by a rotating rod string via a speed increasing transmission. The formation fluid enters the pump intake, usually equipped with a tubing tail as shown and is increased in pressure by the multi-stage centrifugal pump. The high-pressure fluid flows through the transmission assembly via conduits to the tubing at the top end, then on to the surface. The flow conduits passing along side the transmission gear train, but within the pressure housing of the transmission, allows the produced fluid to effectively cool the transmission. The conduits are thin walled D-shaped tubes, whose internal flow pressure is kept in equilibrium with the internal pressure of the transmission via a pressure compensator. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  shows an example of an electrical submersible pump. 
         FIG. 2  shows a detailed pump illustration of an electrical submersible pump according to  FIG. 1 . 
         FIG. 3  shows an example of a geared centrifugal pump. 
         FIG. 4  shows a water cooled electrical submersible pump according to an embodiment of the present invention. 
         FIG. 5  shows a detailed view of a water cooled electrical submersible pump having an internal power cable according to an embodiment of the present invention. 
         FIG. 6  shows a detailed view of a water cooled electrical submersible pump having an internal power cable according to an embodiment of the present invention. 
         FIG. 7  shows a detailed view of a water cooled electrical submersible pump having an external power cable according to an embodiment of the present invention. 
         FIG. 8  shows a water cooled geared centrifugal pump according to an embodiment of the present invention. 
         FIG. 9  shows a detailed view of a water cooled geared centrifugal pump according to an embodiment of the present invention. 
     
    
    
     DETAILED DESCRIPTION 
     Embodiments of the present invention provide for a relatively easy to install and maintain artificial lift pump for use in oil and water pump systems. More specifically, embodiments of the present invention may be used for deep well pumping of oil, water, or other fluid/quasi-fluid. 
     Embodiments of the present invention provide for a deep well pump system having a high volume lift of very hot fluids. Further embodiments of the present invention provide for a deep well pump system which uses some components of available normal temperature electrical submersible pumps to provide a more efficient and less expensive system than current high temperature electrical submersible pumps. 
     Embodiments of the present invention provide for a high volume deep well pumping system adapted to high temperature use by using an external source of cooling fluid to keep the vulnerable pumping apparatus components at an acceptable operating temperature. 
     Embodiments of the present invention provide a method to cool one or more vulnerable components by using a conduit from the surface carrying the cooling fluid, the fluid effectively cooling the components. In further embodiments, the fluid is ejected into the flow stream from the pump and lifted back up to the surface. In an alternative embodiment, a return line brings the cooling water back to the surface with or without mixing it with the production fluid. 
       FIG. 4  shows an example embodiment of a water cooled electrical submersible pump according to the present invention. For example, an externally cooled bottom intake ESP may be provided. In  FIG. 4 , at the bottom end or downhole part of the pump system  400 , the system  400  includes a tubing tail pump intake extension  415  that is equipped with a packer  414  which isolates the perforated casing from the above situated unperforated casing. The tubing tail  415  is attached to the intake of the multi-stage centrifugal pump  413 , and allows communication between the pump intake and the perforated casing below the packer  414 , so that formation fluid entering the casing  405  through the perforations can flow into the pump inlet. Directly above the pump  413  is a motor protector  408 , and the motor  410 , e.g., an electric motor, which drives the pump  413 . For example, the motor  410  and protector  408  are housed inside of a motor shroud  409 , which is then attached to the tubing  406  which extends to the surface. The electrical power for the motor  410  is supplied by a power cable  404  which is run inside the tubing  406  to the motor  410 , or alternatively is run alongside the tubing  406 . Cable or other material attachments  407  can be used to strap or hold the power cable  404  to the tubing  406 . At the top of the pump system  400 , e.g., at the surface, the well may be equipped with a wellhead  402  which may allow a supply of cold water  401  to be pumped down the tubing  406  and through the motor  410  and motor protector  408  and then out through the cooling water outlet  411 , and which may allow the production flowline  403  and valve(s) to carry the produced fluid flowing out of the pump outlet  412  and up the tubing casing annulus to the appropriate facilities/destination(s). 
       FIG. 5  shows a detailed view of a water cooled electrical submersible pump  500  having an internal power cable according to an embodiment of the present invention. In  FIG. 5 , the hot formation fluid enters the formation through the perforations  515  in the casing  505  and flows into the tail end of the tubing  506  and into the pump inlet, above the packer. The pressure of this formation fluid is increased by the multi-stage centrifugal pump  513 . The resulting high-pressure fluid flows into the casing annulus  505  through the outlet  512  at the top of the pump  513 . The packer  514  is needed to isolate the perforated well bore from the high-pressure pump outlet  512 . The pressure inside the well opposite the perforations is at a much lower pressure than that at the pump outlet  512  so that fluid will flow from the formation into the well. The high-pressure fluid then flows to the surface through the casing tubing annulus and into the flow line at the wellhead. 
     In an embodiment, the tubing  506 , which may be used in the normal temperature electrical submersible pump systems as the conduit for the high-pressure formation fluid to flow to the surface, is used in this high temperature electrical submersible pump system to transport cooling water from the surface to the motor  510 , e.g., electric motor, and protector  508  downhole. This cooling water flows down the tubing  506  into the shroud  509  surrounding the motor  510  and protector  508 , along the shroud-motor annulus, and out the cooling water outlet  511  shown. This water very effectively cools the motor  510  and protector  508 , allowing the use of normal temperature components. Also, as shown in  FIG. 5 , the power cable  504  to the motor  510  is run inside the tubing  506  and kept at normal temperatures by the cooling water, eliminating the need for a specialized high temperature cable.  FIG. 5  shows the internal cable  504  coupled to or strapped  516  to a string of rods  507  to both, e.g., support the cable during pulling, but also provide a stiffness to stab the cable  504 , e.g., a flat cable, into a wet-connection  517  at the top of the motor  510 . The water then flows into the well annulus to join the pump outlet fluid and which then flows to the surface. Since in most thermal applications, the majority of the formation fluid pumped to surface is water, adding a relatively small additional amount of water to the well stream provides a negligible operational effect. 
     In an embodiment of the present invention—whether an ESP, GCP, or other system—the tubing carrying the cooling water must be insulated, as it is immersed in produced water and/or oil that can have a high temperature, e.g., a temperature as high as 500° F. If the tubing is not insulated, the cooling water will reach ambient temperature, e.g., ˜500° F. if that is the temperature of the produced or formation fluid, by the time the cooling water reaches the pump and thus provide no cooling effect. For example, in an embodiment, in an about 1500 foot deep well, if the about 1500 feet of about 2⅞″ tubing is fitted with a layer of insulation of about 0.6 inch thick with an R factor of 30, then about 250 bpd of cooling water with a temperature of about 60° Fahrenheit may reach the downhole equipment at a temperature of less than about 160° F., which will very effectively cool the motor. The R factor being a known measure of an insulation&#39;s ability to keep heat in or heat out. The higher the R factor, the better it works as a barrier, and possibly the thicker the insulation. For example, if a smaller about 2⅜″ tubing is used with an about 0.8″ layer of similar insulation, the about 60° F. input water may reach the downhole motor with a temperature of about 120° F. 
     In an embodiment of the present invention, the amount of water required to effectively cool the motor is small compared to the amount of fluid pumped to surface by the pump and motor in a well pump system. For example, assuming the motor is putting about 100 horsepower (HP) into the pump, and the motor and power cable efficiency is about 75%, then power cable must deliver about 133 HP of electrical power to the motor. The about 33 HP that does not go into the pump as mechanical power is instead converted into heat by the motor and cable, and equals, in this example, about 2.7 million British thermal units (BTUs) per day. The about 100 HP of motor input into a pump of average efficiency lifts about 3000 barrels per day of fluid from about 1500 feet depth. The about 1500 feet depth is normal for thermal stimulated oil pools. 
     For example, if about 250 barrels per day (bpd) of cooling water were injected down the tubing of a pump system embodiment according to the present invention, the amount of heat generated by the motor would raise the temperature of the cooling water 31° F. In the situation discussed above, if about 250 bpd of about 60° F. water is injected down about 1500 feet of insulated about 2⅞ inch tubing, the water would reach the motor at a temperature of about 165° F. and be heated to 196° F. as it cools the motor. This temperature is a reasonable operating temperature for available ESP motors. Therefore, the cooling water needed to keep the motor and cable at temperatures within normal design range represents only about an 8% additional volume. The additional energy required to pump the cooling water is also minor. The amount of pressure drop down 1500 feet of 2⅞″ tubing is less than 5 pounds per square inch (psi), so the principal power required to inject the about 250 barrels per day (bpd) of cooling water is that needed to increase the cooling water from atmospheric pressure to that of the produced fluid flow line pressure. For example, a typical flow line pressure can be 150 psi, and the power needed to pump about 250 bpd of water at about 150 psi is less than about 1 HP, a negligible amount. 
     In the specific examples described herein, as well as those that can be contemplated, these apply for ESP, GCP and other pump systems including for the water cooling embodiment of the present invention. Further, different types of motors can be used in the pump systems. Electric motors and their power cables are described herein for purposes of example, but embodiments of the present invention are not limited to use of such motors. 
     In  FIG. 6 , a detailed view of a water cooled electrical submersible pump  600  having an internal power cable according to an embodiment of the present invention is shown.  FIG. 6  shows an alternative embodiment to that shown in  FIG. 5 , by using a round armored cable instead of the flat cable. In this example, the power cable  604  is internal, i.e., located within the tubing  606 . The round cable  604  is sufficiently stiff to allow a wet stab-in connection  613 . A string(s) of wireline  614 , for example, can be strapped around the cable  604  and/or rod string for reinforcement and/or to provide tensional support during pulling of the cable  604  in and out of the well hole. In an embodiment, the power cable  604  is run down the well hole after the pump assembly  611 ,  609  has been run and set in the well. The use of a rod string with the cable strapped to it allows for a relatively flexible cable to be run to bottom and stabbed into a wet connection  613  at the top of the motor  608  in an embodiment of the present invention. Further, running the cable  604  inside insulated tubing  606  to keep temperatures cool is an embodiment of the present invention. 
     In  FIG. 6 , the hot formation fluid enters the formation through the perforations  615  in the casing  605  and flows into the tail end of the tubing  606 , e.g., insulated tubing, and into the pump inlet, above the packer  612 . The pressure of this formation fluid is increased by a pump  611 , e.g., a multi-stage centrifugal pump. The resulting high-pressure fluid flows into the annulus of the casing  505  through the outlet  609  at the top of the pump  611 . The packer  612  is needed to isolate the perforated well bore from the high-pressure pump outlet  609 . The pressure inside the well opposite the perforations is at a much lower pressure than that at the pump outlet  609  so that fluid will flow from the formation into the well, or pump system in the well. The high-pressure fluid then flows to the surface through the casing  605  and into the production flowline at the wellhead. 
     In an embodiment, the tubing  606  is used in this high temperature electrical submersible pump system to transport cooling water from the surface to the motor  608 , e.g., electric motor, and protector  607  downhole. This cooling water flows down the, e.g., insulated, tubing  606  into the shroud  616  surrounding the motor  608  and protector  607 , along the shroud-motor annulus, and out the cooling water outlet  610  shown. This water cools the motor  608  and protector  607 , allowing the use of normal temperature components. Further, the power cable  604  to the motor  608  is run inside the tubing  606  and is kept at normal temperatures by the cooling water, eliminating the need for a specialized high temperature cable. The water then flows into the well annulus to join the pump outlet fluid which then all flows to the surface. 
       FIG. 7  shows an alternative configuration of a high temperature externally cooled ESP  700  which includes an external power cable according to an embodiment of the present invention. In  FIG. 7 , the hot formation fluid enters the formation through the perforations  715  in the casing  705  and flows into the tail end of the tubing  706  and into the pump inlet, above the packer  714 . The pressure of this formation fluid is increased by the pump  713 , e.g., a multi-stage centrifugal pump such as a 513 Series Pump. The resulting high-pressure fluid flows into the casing annulus  705  through the pump outlet  712  at the top of the pump  713 . The packer  714  is used to isolate the perforated well bore from the high-pressure pump outlet  712 . The pressure inside the well opposite the perforations  715  is at a much lower pressure than that at the pump outlet  712  so that fluid will flow from the formation into the well and eventually up through the pump system. The high-pressure fluid then flows to the surface through the casing and into the flow line at the wellhead. 
     In an embodiment, tubing  706  is used in the high temperature electrical submersible pump system to transport cooling water from the surface to the motor  710 , e.g., electric motor such as a 450 Series Motor, and protector  708 , e.g., a 400 Series Protector, downhole. This cooling water flows down the tubing  706  into the shroud  709  surrounding the motor  710  and protector  708 , along the shroud-motor annulus, and out the cooling water outlet  711 . This water effectively cools the motor  710  and protector  708 , allowing the use of normal temperature components. A power cable  704  to provide power to the motor  710  is run alongside the cooling water tubing rather than internally, i.e., inside the tubing  706 . This configuration requires the power cable to be high temperature rated, i.e., manufactured such that it can be used in high temperature environments. For example, a flat #4 Hi-Temp armored cable could be used in an embodiment. The water then flows into the well annulus to join the pump outlet fluid and which then flows to the surface. 
       FIG. 8  shows a water cooled geared centrifugal pump (GCP)  800  which can be used in high temperature situations, e.g., in a deep well or hole and run at a similar speed to that for a normal temperature well, according to an embodiment of the present invention. In this embodiment, the tubing  806  is not used for the flow of the formation fluid to the surface as in a normal temperature GCP, but rather as the conduit for cooling water transmitted down from the surface, e.g., from a cooling water input line  802 . In this embodiment, the GCP does not require a shroud to be placed around the transmission assembly, as there are already internal channels for the flow of fluid that very effectively allow cooling of the internal components by the circulating water. 
     In  FIG. 8 , a production pipe or production flow line  803  is connected to a casing or housing  805  which surrounds and protects downhole elements of the system  800 . Inside the casing  805 , elements such as a rod drive string  804  is run inside a tubing  806  to the GCP transmission assembly  808 . A pump  811  is located just below the GCP transmission assembly  808 , from which the tail end  813  of the tubing  806  is run. Below the tubing tail  813 , the hot formation fluid enters via openings or perforations in the casing  805  and are drawn into or flows into the tubing tail end  813  and into the pump inlet, above the packer  812 . Power for the GCP assembly  808  is provided by a power cable  807  which is run downhole in the tubing  806 . Since the power cable  807  is run inside the tubing  806 , the power cable does not need to be specially manufactured for high temperature operation. The formation fluid is run up through the tubing tail  813  to the packer  812  to the pump  811 , the formation fluid then leaves the pump via the pump outlet  810 . The cooling water, on the other hand, runs from the input line  802  at the surface down through the tubing  806  and passes through the GCP transmission assembly  808 . The cooling water is exhausted via the cooling water outlet  809  into the produced fluid stream exiting the pump outlet  810 , in a similar manner as for the electrical submersible pump embodiments of the present invention described herein. 
     Since the pressure of the hot formation fluid/quasi-fluid is increased by the pump  811 , the resulting high-pressure fluid flows into the casing annulus  805  via the pump outlet  810  situated at the top of the pump  811 . The packer  812  is used to isolate the perforated well bore from the high-pressure pump outlet  810 . Effectively, the pressure inside the well opposite the perforations is at a much lower pressure than that at the pump outlet  812  so that the fluid will flow into the well and eventually up through the pump system. The high-pressure fluid then flows to the surface via the casing  805  and into the production flow line  803  at the wellhead, or other location desired. 
       FIG. 9  shows a detailed view of a water cooled geared centrifugal pump system according to an embodiment of the present invention. In this embodiment, the tubing  906  and GCP transmission assembly  908  are shown coated with thermal insulation  903 . In this embodiment, the hot formation fluid is shown entering the well casing  905  and being drawn into the tubing tail to the packer  912 . The formation fluid is then pumped, e.g., via a 513 Series Pump  911 , up through the pump outlet  909  into the casing  905 . In order to keep cool the GCP assembly  908  which runs the pump  911 , cooling water or fluid is sent down through tubing  906  alongside the rod drive string  904  and is passed through the GCP assembly  908 . The cooling water then is passed out the outlet  910  of the GCP assembly  908 , and mixes with the pressurized by the pump formation fluid. The fluid then flows through the casing  904  to the surface or other destination. In an embodiments of the present invention, the cooling fluid may be water, or any other fluid appropriate for use with such equipment. Further, various types of models can be used for the GCP assembly, pump, cable, tubing, casing, and other features. Given the flow of a fluid in the pump system, when there is water present as a flow agent, it may be desirable to use water-resistant coated materials to prevent corrosion. Likewise, the same follows for use of other types of fluids. 
     It should be understood that there exist implementations of other variations and modifications of the invention and its various aspects, as may be readily apparent to those of ordinary skill in the art, and that the invention is not limited by specific embodiments described herein. Features and embodiments described above may be combined with and without each other. It is therefore contemplated to cover any and all modifications, variations, combinations or equivalents that fall within the scope of the basic underlying principals disclosed and claimed herein.