Abstract:
The present invention is directed to methods for extracting fluids from oil and gas wells. More specifically, it is directed toward methods and apparatuses to power and control down hole hydraulic devices using subterranean centrifugal pumps. This invention represents a vast improvement over current hydraulic artificial lift systems. This invention provides for safe, efficient, and increased fluid recovery of oil and gas reserves from subterranean reservoirs in all types of wells, including deviated and horizontal wells.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     The present application claims priority to U.S. Application No. 61/321,605, which was filed on Apr. 7, 2010, entitled METHOD AND APPARATUS TO OPERATE AND CONTROL SUBMERSIBLE HYDRAULIC MOTORS, the disclosure of which is incorporated by reference. 
    
    
     TECHNICAL FIELD 
     The present disclosure is directed to methods and apparatus to extract fluids from subterranean reservoirs, particularly oil and gas reservoirs. More specifically, this disclosure provides methods and apparatuses to increase the recovery of fluid reserves, such as oil and gas, from subterranean reservoirs using an improved hydraulic system to power subterranean devices. 
     BACKGROUND OF THE INVENTION 
     When a fluid, such as oil and natural gas, is being produced from a subterranean reservoir, the reservoir may not have sufficient energy, or the reservoir strata may have insufficient fluid conductivity, to eject fluids to the surface at a commercial fluid flow rates. A conventional method to recover fluids from a reservoir that has inadequate fluid conductivity is hydraulic fracturing. This hydraulic fracture treatment often allows reservoir fluids to be recovered at commercial rates. This benefit, however, is typically only temporary because fluid production to the surface will usually decline as fluids are extracted from the reservoir. In the case of a reservoir producing natural gas, the reservoir energy is normally depleted until it no longer ejects all the fluids out of the well. 
     As the fluids begin to accumulate in the well due to decreased flow conductivity, this accumulation further causes a hydrostatic fluid pressure that is exerted against the pressure of the subterranean reservoir, thereby reducing the flow of fluid to the surface. With time, this condition will eventually cause the well to stop producing fluid to the surface. 
     Another known method to increase fluid production is to insert a smaller conduit known as a velocity string into the well casing, to allow fluids to rise to the surface at a higher velocity. Higher fluid velocity has been found to increase the amount of fluid that can be lifted out of a well. Generally, both these methods may be combined to improve production of a low fluid conductivity reservoir. For instance, a reservoir may be hydraulically fractured then a velocity string may be inserted coaxially inside the casing to produce additional well fluids up the velocity string. 
     As mentioned above, increased fluid production from a hydraulically fractured well having a velocity string is not maintained indefinitely. Instead, as the reservoir pressure continues to be depleted during fluid extraction, the fluid velocity in the coaxially inserted velocity string becomes insufficient to lift the well fluids to the surface at a commercial production rate. Consequently, fluids begin to accumulate in the well and once again exert a hydrostatic pressure against the reservoir. While, additional smaller velocity strings can be coaxially inserted to increase fluid velocity, this method has its drawbacks. For instance, each new smaller velocity string reduces the fluid flow rates to the surface due to the increasing fluid friction in the velocity string as the diameter decreases. Further, inserting additional velocity strings does not address the decreasing reservoir energy as a reservoir is depleted of fluids, where the reservoir energy continues to decrease until it is insufficient to lift fluids to the surface at commercial rates. 
     Moreover, inserting additional velocity strings is inconvenient and not commercially expedient because to use the well configuration that was lastly deployed rather than extracting the final well configuration with an expensive rig intervention only to deploy some other configuration for further extracting well fluids at the current conditions. At this point in the life of a well generally known method of artificial lift is used to further extract fluid from the reservoir without substantially changing the well configuration, i.e., without pulling the last velocity string that was disposed in the well. 
     The known artificial lift pumping methods of the prior art were originally developed to extract oil and water from subterranean reservoirs. As such, these known artificial lift methods may not be best suited for extracting fluids from gas wells. There is still a need for applicable artificial lift means to operate in natural gas wells to assist in removing the fluids from such wells as the reservoir energy and correspondingly fluid flow velocities decrease to allow for commercial quantities of natural gas to be produced. Moreover, as natural gas wells are constructed deeper and deeper with more well bore deviation (indeed even horizontal orientations in such well bores are used through subterranean reservoirs), the need for a suitable means to lift fluids from the gas wells has increased. 
     There are various conventional artificial lift devices and methods, particularly used in the oil and gas industry, including gas lift, electrical submersible centrifugal pump systems, surface beam pumps with down hole traveling valves, surface electrical motors rotating rods from surface and attached to a well progressive cavity pump, hydraulic jet pumps, hydraulic piston pumps. 
     Also, the conventional hydraulic submersible artificial lift methods often involve the use of positive displacement piston pumps located at the surface to power the down hole hydraulic motors, engines, and pumps. An example of such pumps is disclosed in U.S. Pat. No. 2,081,221 to Clarence J. Coberly. These conventional systems of hydraulically lifting fluids from oil and gas wells introduce significant environmental hazards because they place high pressure hydraulic positive displacement piston pump systems at the surface. 
     It is further known to those familiar with producing oil and gas wells with hydraulic pumping systems that the use of water as a power fluid is limited in cold climates. The power water fluid is often heated or treated with freeze depressant chemicals to avoid freezing. This has many disadvantages, including extra energy use and the possibility of introducing hazardous chemicals into the environment. 
     The field of dewatering gas wells or as it is often known in the oil and gas industry as artificial lifting gas wells, is reluctant to adopt the current methods of hydraulic powered submersible hydraulic motors, engines, compressors, and pumps as most are currently powered by surface positive displacement piston pump systems. These conventional art uses of surface located positive displacement systems are dangerous and often outlawed by city ordinances for many reasons. In particular, there are likely risks associated with these systems, such as over pressurization of the surface equipment when a well hydraulic fluid system plugs, or a surface valve closes on the positive displacement tri-plex pumps discharge side, which causes a high pressure release of hydraulic power fluid. 
     Further, the conventional positive displacement pumps placed at the surface have large dimensions that cannot easily be accommodated in a well conduit and hence are located on the surface of the earth or at best on small skids with fluid containments beneath them. This configuration also introduces risks both at the surface environment and into a hydraulic power system, as an inadvertent closure of a valve, or the plugging of a valve, can cause a rapid pressure rise in the positive displacement pumps discharge often resulting in a catastrophic rupture and leak of the hydraulic power system. This catastrophic pressure rupture causes oil spills, fires, pollution, and danger to humans. Additionally, the conventional hydraulic power pumps surface arrangements have packing, and oil lubricants in their power ends that can leak and spill oil on the earth&#39;s surface. Hence the conventional hydraulic pumping system for lifting fluids from wells have many drawbacks including continual and frequent oil changes, and pump maintenance further introducing the opportunity to have an oil spill at the surface. 
     Additional drawbacks include a large surface footprint, which makes the conventional systems difficult to house or encapsulate to contain leaks from the pump system. What is needed is a method to hydraulically power submersible hydraulic motors with a hydraulic power systems that can be disposed below the surface in a containment means to avoid oil spills, and dangers if such a high pressure pump catastrophically fails. 
     In view of the disadvantages of the current system, there is a need for a hydraulic power pumping system that does not involve positive displacement pumps located at the surface to address the drawbacks of current systems such as frequent lubricant changes, lubricant additions; catastrophic conduit failure caused by valve closure or conduit plugging; and heating or treating operating fluid functional in cold climates. 
     BRIEF SUMMARY OF THE INVENTION 
     To meet the needs discussed above and address the disadvantages of conventional systems, the present disclosure provides a submersible hydraulic lift system comprising a first submersible pump assembly and a first submersible hydraulic engine component connected to a first submersible hydraulic transducer component. At least a portion of said first submersible pump assembly is located below the surface. Further, at least a portion of said first submersible hydraulic engine is located below the surface. The first submersible hydraulic transducer component has a hydraulic fluid connection with one or more fluids of a subterranean reservoir. The submersible hydraulic lift system further comprises a first fluid path that hydraulically connects the first submersible pump assembly with the first submersible engine component. The first submersible pump assembly is configured to hydraulically drive the first submersible hydraulic engine component by transferring power liquid from the first submersible pump assembly to the first submersible hydraulic engine component through the first fluid path. 
     In one embodiment, the system further comprises a second fluid path that hydraulically connects an output of the first fluid transducer component with the surface. The hydraulically driven first submersible engine component is configured to drive the connected first submersible hydraulic transducer component. The driven first submersible hydraulic transducer component is configured to extract the one or more reservoir fluids and discharge the one or more reservoir fluids into the second fluid path. 
     In another embodiment, the first submersible pump assembly comprises a submersible electrical motor component, a submersible pump component, and a pump intake component, where the submersible pump intake component is connected to said electrical motor component and said submersible pump component and where the submersible electrical motor component is connected to said submersible pump component where a rotation of said submersible electrical motor component results in the rotation of said submersible pump component. 
     In yet another embodiment, the submersible pump component comprises a centrifugal pump. In another embodiment, the fluid transducer comprises a submersible hydraulic pump. Alternatively, the fluid transducer comprises a submersible hydraulic compressor. In another embodiment, the system further comprises a frequency drive machine configured to control the revolutions per minute of said submersible electrical motor component. 
     In another embodiment, the system further comprises a commercialization fluid path, said commercialization fluid path hydraulically connecting said second fluid path with a commercialization point. 
     In another embodiment, a portion of said first submersible pump assembly is disposed in a first casing of a first well and wherein a portion of said first submersible hydraulic engine component and a portion of said first submersible hydraulic transducer component are disposed in a second casing of a second well. In this embodiment, the system further comprises a second submersible hydraulic engine component connected to a second submersible hydraulic transducer component. At least a portion of said second submersible hydraulic engine is located below the surface, said submersible hydraulic transducer component having a hydraulic fluid connection with one or more fluids of said subterranean reservoir. The system further includes a third fluid path, said fourth fluid path hydraulically connecting said first submersible pump assembly with said second submersible engine component. The first submersible pump assembly is configured to hydraulically drive said second submersible hydraulic engine component by transferring power liquid from said first submersible pump assembly to said second submersible hydraulic engine component through said third fluid path. The system further includes a fourth fluid path, said fourth fluid path hydraulically connecting an output of said second fluid transducer component with the surface. The hydraulically driven second submersible engine component is configured to drive said connected second submersible hydraulic transducer component. The driven second submersible hydraulic transducer component is configured to extract said one or more reservoir fluids and discharge said one or more reservoir fluids into said second fluid path. 
     In another embodiment, the system further comprises an acoustic monitoring component. The acoustic monitoring component comprises at least one surface acoustic sensor connected to said first fluid path and to a controller component, said controller component connected to said a power source of said first submersible pump assembly. The at least one surface acoustic sensor is configured to receive one or more acoustic signals generated by said first submersible hydraulic engine and transferred through said first fluid path. The at least one surface acoustic sensor is also configured to transmit to said surface controller data corresponding to said received one or more acoustic signals. The controller component is configured to manage at least fluid discharge pressure and rate of said first submersible hydraulic engine by controlling said power source. In one embodiment, the data is transmitted wirelessly. Alternatively, the data is transmitted by a submersible acoustic signal transmission system connected to said at least one surface acoustic sensor and said controller component. 
     In another embodiment, the system of claim  1  wherein said second fluid path comprises a subterranean conduit. In yet another embodiment, the power fluid is selected from a group consisting of propane, ammonia, water, oil, and any combination thereof. 
     According to another aspect of the present disclosure, there is provided a method for operating a submersible hydraulic engine comprising the steps: operating a first submersible pump assembly, wherein at least a portion of said first submersible pump assembly is located below the surface and hydraulically driving a first submersible hydraulic engine component by said operation of said first submersible pump assembly, wherein at least a portion of said first submersible hydraulic engine is located below the surface. The step of hydraulically driving comprises transferring of power fluid by said first submersible pump assembly from said first submersible pump assembly to said first submersible hydraulic engine component through a first fluid path, said first fluid path hydraulically connecting said first submersible pump assembly with said first submersible engine component 
     In one embodiment, the method further comprises driving a first submersible hydraulic transducer component connected to said first submersible hydraulic engine component by said hydraulically driving step. The first submersible hydraulic transducer component has a hydraulic fluid connection with one or more fluids of a subterranean reservoir. The method further comprises discharging said power fluid into a second fluid path, said second fluid path hydraulically connecting an output of said first fluid transducer component with the surface; extracting said one or more reservoir fluids by said first submersible fluid transducer; and discharging said one or more reservoir fluids by said first submersible fluid transducer into said second fluid path, wherein said power fluid mixes with said one or more reservoir fluids. 
     In another embodiment, the method further comprises collecting said fluid mixture at the surface from an output of said second fluid path; and separating from said collected fluid mixture said one or more reservoir fluids by a separator component. In yet another embodiment, the method further comprises transferring said separated one or more reservoir fluids to a commercialization point through a commercialization fluid path, said commercialization fluid path hydraulically connecting said second fluid path with a commercialization point. 
     In another embodiment, the method further comprises driving a first submersible hydraulic transducer component connected to said first submersible hydraulic engine component by said hydraulically driving step. The first submersible hydraulic transducer component having a hydraulic fluid connection with one or more fluids of a subterranean reservoir. The method further comprises discharging said power fluid into a return fluid path, said return fluid path hydraulically connecting an output of said first fluid transducer component with an input of said first submersible pump assembly; extracting said one or more reservoir fluids by said first submersible fluid transducer; and discharging said one or more reservoir fluids by said first submersible fluid transducer into said second fluid path, wherein said power fluid mixes with said one or more reservoir fluids and wherein at least a portion of said power fluid comprises a portion of said fluid mixture. 
     In another embodiment, the method further comprises collecting said fluid mixture at the surface from an output of a collection fluid path, said collection fluid path hydraulically connecting an output of said return fluid path with an input of a separator component; and separating from said collected fluid mixture said one or more reservoir fluids by said separator component. 
     In another embodiment, the method further comprises monitoring one or more acoustic signals generated by said first submersible hydraulic engine with at least one surface acoustic sensor connected to said first fluid path and to a controller component. The controller component is also connected to said power source of said first submersible pump assembly. The method further comprises managing at least fluid discharge pressure and rate of said first submersible hydraulic engine by controlling said power source. 
     The foregoing has outlined rather broadly the features and technical advantages of the present invention in order that the detailed description of the invention that follows may be better understood. Additional features and advantages of the invention will be described hereinafter which form the subject of the claims of the invention. It should be appreciated by those skilled in the art that the conception and specific embodiment disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the present invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims. The novel features which are believed to be characteristic of the invention, both as to its organization and method of operation, together with further objects and advantages will be better understood from the following description when considered in connection with the accompanying figures. It is to be expressly understood, however, that each of the figures is provided for the purpose of illustration and description only and is not intended as a definition of the limits of the present invention. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  illustrates general well construction and production enhancement phases during the life of a well. 
         FIG. 2  illustrates a general final well configuration of the fluid production process. 
         FIG. 3  shows a general configuration of surface equipment used during the final well configuration in the fluid production process. 
         FIG. 4  illustrates an embodiment of a hydraulic fluid system of the present disclosure. 
         FIG. 5  illustrates another embodiment of a hydraulic power system of the present disclosure. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     As used herein, “a” or “an” means one or more. Unless otherwise indicated, the singular contains the plural and the plural contains the singular. Where the disclosure refers to “perforations” it should be understood to mean “one or more perforations”. 
     As used herein, “surface” refers to locations at or above the surface of the earth. 
     Referring to  FIG. 1 , sequential phases of an embodiment of the well construction and production enhancement process of the present disclosure are shown. During the first phase illustrated by  FIG. 1A , well bore  1  is drilled using a drilling rig  2 , which has a drill pipe  4  attached. Drill pipe  4  has drilling bits  3  attached to its distal end that allows for drilling of well bore  1 . After the well bore  1  is drilled to a desired depth and diameter, a casing is placed within the well bore  1 . The drilling equipment and method to drill well bore  1  are known to those skilled in the art. Referring to  FIG. 1B , the next phase involves the wellbore  1  being grouted with cement from a cement bin  5 , preferably pneumatic, where the cement is mixed with water from a source tank  6  through a cement pump unit  7  forming a cement grout slurry. This slurry is transferred through the well casing  8  down into the well. The slurry is displaced with water from the source tank  6  with a cement plug  9 , and this displacement forces the cement grout out of the internal diameter of the casing  8  and into the annular space  10  formed by the outer diameter of casing  8  and the well bore  1 . Again, the equipment used to install casing  8  is known to one of ordinary skill in the art. 
     Referring to  FIG. 1C , the next phase of the well construction process involves perforation, where a perforating truck  11  deploys a perforating gun assembly  12 , which is on wire line  13 , into the well casing  8 . The perforating gun assembly  12  forms a fluid flow path between the inside of the casing  8  and the subterranean reservoir  14  by creating perforations  17  through the well casing  8  and the cement grout located in the annular space  10 . Referring to  FIG. 1D , the reservoir  14  is hydraulically fractured by a fluid that is pumped from a surface frac tank  16  through at least one surface pumping unit  15  down the casing  8  through perforations  17 . Referring to  FIG. 1E , after the hydraulic fracturing treatment, fluids usually flow from the reservoir  14  through the perforations  17  up the casing  8  through the well head  18  to the surface. Referring to  FIG. 1F , the well of well bore  1  with a second well conduit  19  that is inserted coaxially within the casing  8 . The second well conduit  19  is hung off from the well head  18 , which allows reservoir fluids to flow from reservoir  14  through perforations  17  and up both the internal diameter of the second well conduit  19  to the surface and the annular space  20  formed by the outer diameter of the second well conduit  19  and the internal diameter of casing  8 . The output of well fluids flowing up the internal diameter of the second well conduit  19  is through port  21  while the output of well fluids flowing up the annular space  20  is through port  22 .  FIGS. 1A-1F  generally illustrate the process of drilling and establishing a well bore. According to another aspect of the present disclosure, other known means of drilling and installing a well can be used. Also, the hydraulic lift system of the present disclosure is also applicable to horizontal or deviated wells. 
     Referring to  FIG. 2 , the phase subsequent to the phase in  FIG. 1F  in well construction is illustrated. In  FIG. 2 , a third conduit of continuous tubing  201  is inserted through the well head  18  so that it is placed coaxially inside the second conduit  19 .  FIG. 2  further illustrates a hydraulic motor  202  disposed in the second tubing  19  and attached to the distal end of the continuous tubing  201 . Also shown in  FIG. 2  is a fluid transducer device  203  attached to the hydraulic motor  202 . The discharge  204  of the fluid transducer  203  is separated from the intake  205  of the fluid transducer  203  by a sealing means  206  located inside the second tubing  19 . One example of such a sealing means is a series of elastomeric rings located on the outer diameter of pump body  203  where the elastomeric rings seal into a corresponding polished bore receptacle means inside the second tubular conduit  19 . Another example of such sealing means includes sealing the metallic outer surface of the pump  203  that is engaged with sealing means  206  where sealing means  206  can be a metal receptacle, preferably tapered. The seal is such that the outer metallic diameter of the pump  203  forms a metal to metal seal with the tapered metal receptacle  206 . Other sealing means known in the art are also applicable and can be used with the hydraulic lift system of the present disclosure. 
       FIG. 2  further illustrates fluid flowing from the reservoir  14  through perforations  17  into the well casing  8  into the intake  205  of the fluid transducer  203  and transported through the fluid transducer  203  and through the discharge  204  of the fluid transducer  203  into the annular fluid flow path  207 , which is formed between the outer diameter of the continuous tube  201  and the internal diameter of the second well conduit  19 . The well fluid is further transported to the surface through port  21  of the well head  18  at the surface. The configuration of  FIG. 2  allows fluids to simultaneously flow from the reservoir  14  through the perforations  17  into the casing  8  and up the annular space  20  through port  22  of the well head  18  located at the surface.  FIG. 2  further depicts fluid  209  being transduced down from the surface through the continuous tubing  201  through the hydraulic motor  202  and exhausted out of the motor  202  at the motor discharge  208  where fluid  209  mixes with produced well fluids in the annular space  207 . The mixture of fluid  209  and well fluid is produced to the surface through port  21  of well head  18 . A tubing injector device  210  may be used to insert the continuous tubing  201  through the well head  18  coaxially through the second tubing  19  and landing the fluid transducer  203  into a sealing means  206 . One example of the tubing injector device  210  is a hydraulic injector head, which is often used with coiled tubing. Other similar devices known to one of ordinary skill in the art to insert continuous tubing  201  as described can be used. 
     The submersible hydraulic motor or hydraulic engine  202  used to lift well fluids from reservoirs may be connected to hydraulic jet pumps and hydraulic piston engines, hydraulic motors, and hydraulic piston pumps like those described in U.S. Pat. No. 1,577,971 to Ira B. Humphreys, the disclosure of which is incorporated by reference. In other embodiments, submersible hydraulic fluid transducer  203  may include those described in U.S. Pat. No. 2,081,220 to Clarence J. Coberly, the disclosure of which is incorporated by reference. 
     The fluid  209  may include water and/or chemicals suitable to reduce friction and wear in the system as well as chemicals suitable to treat corrosion and scale formation. Examples of the fluid include propane, ammonia, water, oil, or any combination thereof. In one embodiment, the fluid transducer  203  is a pump, preferably submersible. In another embodiment, the fluid transducer  203  is a compressor, preferably submersible. 
       FIG. 3  illustrates one configuration of the relationship between the final sequential phase of the well depletion method illustrated in  FIG. 2  and a hydraulic power fluid system. In  FIG. 3 , a surface pump  301 , this is on a prime mover skid. The surface pump  301  receives fluid from a source tank  302 , where the fluid passes through a fluid filter  303 . The surface pump  301  also receives a second fluid  309  from a second source tank  304 . Fluid  309  may be delivered to surface pump  301  by an injection pump  305 , which may be powered, for example, by a solar panel  306 . In other embodiments, the injection pump may be powered by other means such as battery or electricity from an outlet. The combined fluid of the fluid from tank  302  and fluid  309  becomes fluid  209 , which is then pumped from the surface pump  301  through a filter  307  through a control valve  308  where fluid is allowed to flow either into the continuous tubing  201  or back to the surface tank  302 .  FIG. 3  further illustrates well fluids being produced through port  22  into a surface separator  310  where the fluids, such as gases, from the well are separated and the desired well fluid is transferred to another location through line  311 . The separator  310  further separates the hydrocarbons from water and the hydrocarbons are flowed to tank  312  and the water portion is transferred to a series of large filters  313 . The filtered water is then transferred to the tank  302 . 
     In general,  FIG. 3  illustrate the well fluid being discharged from the subterranean fluid transducer  203  and the exhaust of the submersible hydraulic motor  202  flowing to the surface through port  21  of the well head  18  into the separator  310 . The fluids can be separated into gas, water, and hydrocarbon streams in the separator  310 . The hydrocarbon stream is then directed into the tank  312 , the water stream is directed into the filters  313  thereafter into the surface tank  302 , and the gas is directed to line  311 . 
       FIG. 3  further illustrates the use of an acoustic sensor device in the hydraulically powered artificial lift system described by the present disclosure. The acoustic sensor device allows the system to be operated within the desired parameters, thereby controlling any over pressurization by, or damages to, the system. 
     In particular,  FIG. 3  depicts an acoustic sensing device  314  receiving acoustic signals from the continuous tube  201 . The acoustic signals are generated by the mechanical piston reciprocation of the submersible fluid transducer  203  and the submersible hydraulic motor  202 . The acoustic sensor  314  transmits a signal to a surface controller  315  that controls the injection pump  305  and the surface pump  301 . In one embodiment, the surface pump is preferably powered by a gas supply brought by gas line  317 . The gas comes from a portion of the gas supplied by the separator  310 , which also sends gas to  316 . In another embodiment, controller  315  may be a computer device operable to process the data sent from the acoustic sensor  315  and control the injection pump  305  and surface pump  301 . 
     With regard to acoustic sensors devices, existing electrical acoustic sensors are broadly defined by one of three types: (1) microphones mounted on an acoustic sensors diaphragm, (2) piezo-electric sensors mounted on, or physically connected to, the acoustic sensors diaphragm, and (3) capacitive acoustic sensors. The application of any of the three broad classes of acoustic sensors as well as other acoustic sensing means is within the scope of the embodiments of the present disclosure. According to one aspect, the acoustic energy is transmitted from the submersible hydraulic motor and submersible fluid transducer up the continuous tube  201  of  FIG. 2  or  3  to the acoustic sensor  314 , where the acoustic sensor  314  is engaged with the continuous conduit  201 . 
     Generally, the acoustical vibration received by the acoustic sensor  314  is converted into an electrical signal through a variety of methods known to those familiar with hydrophones and microphones using for example piezoelectric sensors, microphones, or capacitive acoustic sensors. This electrical signal is then transferred to the controller  315  of  FIG. 3  wherein the electrical signal is evaluated and compared to acoustical frequencies and pulses of the submersible hydraulic motor and fluid transducer that are stored in controller  315  or provided to controller  315 . The controller algorithms are then used to increase or decrease the power operating the surface pump  301  and the injection pump  304  of  FIG. 3 . This, in turn, controls the down hole hydraulic motor  202  and fluid transducer  203 . 
     According to one aspect of the present disclosure, the controller  315  preferably will have pre-set values, stored or provided to it, that will allow for the maximum and minimum frequencies of acoustic pulses coming from the submersible hydraulic motor  202  and submersible fluid transducer  203 . The controller  315  will allow the surface pump  301  to discharge fluids into the continuous tube  201  of  FIG. 3  between these pre-set maximum and minimum frequency values. If for example the frequency of the acoustic pulses received by the acoustic sensor  314  exceeds the maximum allowable frequency, the controller  315  can send an electrical signal to solenoids that will close the gas flow from gas line  317  into the surface pump  301 . The solenoids can also disconnect the power to the injection pump  305 . The controller  315  may be set to keep the surface pump  301  and injection pump  305  off for a pre-set period of time before the surface pump  301  and injection pump  305  are restarted. Likewise, the controller  215  can be used as a timer to turn off the surface pump  301  and injection pump  305  for a period of time each day. 
     Referring to  FIG. 4 , one embodiment of the hydraulic fluid lifting system, system  400 , of the present disclosure is shown. In particular, system  400  can incorporate the well configuration shown in  FIG. 2  and the corresponding descriptions provided above. In one embodiment, the well configuration of  FIG. 2  may be installed as shown in  FIGS. 1 and 2 . In another embodiment, the well configuration may be installed by other known methods. In  FIG. 4 , a caisson  405  is placed into the earth  401 . The caisson  405  forms a closed sub-surface housing for the deployment of a submersible electrical motor  406 , a submersible pump thrust bearing inside an electrical motor protector  407 , a submersible pump intake  408 , and a centrifugal pump  409 . The electrical submersible motor  406  is connected to a submersible electrical cable  410 , which is connected to an electrical power source  411  through a surface electrical power cable  412 . Electrical power is conducted from the surface power source  411  through the surface electrical power line  412  down into the caisson  405  by the submersible power cable  410 . The electricity powers the submersible electrical motor  406 , which is connected to the submersible pump  409  by a common shaft. As such, the reciprocation, or movement, of the submersible electrical motor  406  results in the rotation of the centrifugal pump  409 , which transforms electrical power into hydraulic power. Thus, operating submersible electrical motor  406  moves fluid from caison  405  through the pump  409  through conduit  413  and high pressure line  416  to well hydraulic engine  420 . In particular, the pump  409  draws fluid through the submersible pump intake  408 , and the fluid is transferred through the centrifugal pump  409  into the conduit  413 . Fluid is supplied to the caisson  405  from a surface tank  414  through a surface conduit  415 . Fluid is discharged from the submersible centrifugal pump  409  at high pressure that is sufficient to power a down hole hydraulic engine  420 , which may correspond with engine  202  of  FIG. 2 . 
     As shown by  FIG. 4 , fluid is transferred from the caisson  405  to hydraulic engine  420  disposed in a production conduit  422 , which is disposed in a well casing  421 . The fluid is transferred through the submersible pump  409  up through the conduit  413  and surface high pressure line  416  down the well casing  421  and through a hydraulic conduit, or production conduit,  422 , which is inserted coaxially within the well casing  421 . Well casing  421  can be a casing in a gas well or other types of well such as oil or water. The hydraulic engine  420  and hydraulic pump  423  are attached to the distal end of hydraulic conduit  422 . The suction and discharge of the submersible pump  423  are separated from one another by an elastomeric seal device  424 , which is similar to seal means  206  described in  FIG. 2 . In this embodiment, the submersible hydraulic pump  423 , which can correspond to hydraulic pump  203  of  FIG. 2 , in a well casing  421  is powered with power fluid  432  from centrifugal pump  409 , which is located in a separate well. The pump  409  in caisson  405  can power submersible hydraulic pumps in a plurality of wells using known methods of pad drilling and completion techniques where many wells are drilled from a common surface pad location and the wells are deviated and terminated in different locations of a subterranean reservoir. The fluid  432  may include water and/or chemicals suitable to reduce friction and wear in the system as well as chemicals suitable to treat corrosion and scale formation. Examples of the fluid include propane, ammonia, water, oil, or any combination thereof. 
       FIG. 4  further depicts the submersible hydraulic pump  423  connected to hydraulic engine  420  and disposed inside the production conduit  422  where the well fluid  433  can be produced from subterranean reservoirs  430  through the pump  423 . As shown, pump  423  draws the well fluid  433  through its intake and discharges well fluid  433  into the production conduit  422 , which also has the exhausted power fluid  425  discharged from hydraulic engine  420 . The well fluid  433  and power fluid  425  are mixed and produced to the surface conduit  426  and into a liquid/gas separator  427 . The liquid/gas separator  427  separates gas from the mixture and directs the gas to line  428  for commercialization. The remaining fluid production is transferred through line  431  back to a storage tank of  414 . Separator  427  may also be replaced by and/or include additional devices that separate other types of well fluids, such as hydrocarbon, from the mixture. The separated well fluids may be similarly directed to commercialization. A wide variety of filters, settling tanks, separation tanks, chemical injection pumps and fluids can be inserted in storage tank  414  to enhance the fluid properties being fed to the submersible pump  409 . These enhancements include reducing solids, adding lubricants, corrosion inhibitors, oxygen scavengers, and scale inhibitors. 
     Referring to  FIG. 4 , fluids from the subterranean hydrocarbon reservoirs  430  that are not transferred to the surface through the annulus  434  between the outer diameter of the high pressure line  416  and inner diameter of the production conduit  422  are still allowed to flow up the well casing  421  to the surface. In particular, these fluids  435 , such as gases from the reservoir, can flow through the annulus  436  between the outer diameter of production conduit  422  and inner diameter of well casing  421  to the surface and commercialized through surface line  437 . As shown, it is clear to those familiar with the art of gas wells that the system  400  allows gas wells to be de-liquefied using the submersible hydraulic fluid pump  423  whilst producing and commercializing gas up the annulus  436  between the outer diameter of production conduit  422  and inner diameter of well casing  421 . 
     The system  400  of  FIG. 4  uses a hydraulic pump as an illustrative example of a fluid transducer powered by a submersible hydraulic engine to deliquify a gas well or to extract well fluids from gas wells, along with other types of wells. In other embodiments, however, other fluid transducer, such as compressors, can be used without departing from the spirit and scope of the embodiments of the present disclosure. 
     In other embodiments, the submersible hydraulic piston engine  420  and the submersible hydraulic piston pump  423  may be replaced with a jet pump. In yet another embodiment, the submersible hydraulic engine  420  may be replaced with a rotating hydraulic motor connected to a rotating submersible well fluid pump like a centrifugal pump or a progressive cavity pump. 
     As shown in  FIG. 4 , system  400  allows for the well fluid to be brought to the surface without the use of positive displacement pumps located at the surface. Additionally, system  400  provides housing for the hydraulic power supply system that protects the environment from any damages that may occur during the operation of the system  400 . 
     Referring to  FIG. 5 , another embodiment is depicted system  500 , which can also incorporate the well configuration of  FIG. 2  and the corresponding descriptions provided above. In one embodiment, the well configuration of  FIG. 2  may be installed as shown in  FIGS. 1 and 2 . In  FIG. 5 , centrifugal pump  510  is located in subterranean enclosure  511 . The centrifugal pump  510  pumps hydraulic power fluid  512  to a submersible hydraulic engine  520 , which may correspond with engine  202  of  FIG. 2 , located in well  530 , which is separate from subterranean enclosure  511 . In other embodiments, there may be more than one well with a submersible hydraulic engine that is also powered by centrifugal pump  510 . The submersible hydraulic engine  520  is connected by a shaft to a submersible hydraulic pump  521 , which can correspond to hydraulic pump  203  of  FIG. 2 . This results in the reciprocation of the shaft of the hydraulic engine  520  driving the connected submersible hydraulic pump  521 . The pump  521  draws well fluids like liquids  532  from reservoir  531  that is hydraulically communicated with the well  530  through perforations  522 . Well fluids from reservoirs  531  may be separated into two streams: one stream of gas  533  that expands to surface  534  that may be collected and one stream of liquids  532 . The well gases  533  are vented and transferred to one of conduits  550 ,  551 , and  552  for commercialization. The well liquids  532  can be transferred to the surface through a production tubing  535  and combined with the exhausted power fluid  512  exiting the submersible hydraulic engine  520  forming a new combined liquid mixture  538 . The combined liquid  538  of produced liquids  532  and exhausted power fluid  512  are transferred back to the casing  513  through an underground conduit  514 . This subterranean transfer of fluids from well  530  to the subterranean casing  513  keeps the fluids from freezing in cold environments, and affords for a safer well location as all lines are underground where trucks, cranes, and people cannot damage them. 
     The process as depicted in  FIG. 5  operates by first filling the casing  513  with transfer fluid  515  in process tank  516 . Tank  516  is also used to accumulate and transfer fluids out of the system for commercialization, like condensate and oil. Likewise, it is used to remove from the process water produced from the well  530 . It is clear to those familiar with oil and gas production that the process tank  516  can be manifolded with a plurality of tanks to allow for sustained operation such that the tanks are a buffer to the system keeping the centrifugal pump intake  517  flooded as well as storing produced well fluids from the system. The fluid from tank  516  is then connected to the casing  513  and level control devices are used on tank  516  as is well known to those familiar with the art of dump valves and separator fluid dump mechanisms to assure the fluid level in the casing  513  is above the centrifugal pump intake  517 . 
     The submersible centrifugal pump  510  then pumps fluid  512  from casing  513  through a subterranean fluid conduit  543  to power the submersible hydraulic engine  520  thereby lifting liquids from the well  530  through a submersible pump  521  and transferring the well liquids  532  and hydraulic power fluids  512  back to the casing  513  and the submersible pump  510 . The submersible electrical motor  518  can be powered with electricity from a generator  519 . The speed of the submersible electrical motor  518  may be controlled by a frequency drive controller  540  and the electrical power is then transferred to the submersible electrical motor  518  through the electrical cable  541  and converted to shaft horsepower. The submersible electrical motor  518  shaft is connected to an electrical motor protector  542  by coupling the shafts of these two devices thereby transferring the shaft power through the electrical motor protector via a shaft that goes through the pump intake  517  to a shaft connection to the submersible centrifugal pump  510 . Each of these four devices: the submersible electrical pump  518  the electrical motor protector  542 , and the pump intake  517  and the submersible centrifugal pump can also be connected by flange and threaded connection into an assembly that is connected to a fluid conduit  543  and disposed inside the subterranean casing  513 . 
     While not shown, other embodiments of  FIGS. 4 and 5  may incorporate all or certain features of the configuration shown in  FIG. 3 , such as acoustic system. For instance, the controller device  315  may be connected to power source  411  of  FIG. 4  or power source  519  of  FIG. 5  to control the flow and pressure in fluid conduit  422  and  543 , respectively, as described above to operate the hydraulic lifting system within desired parameters. Also, while the description may use gas as an example of a well fluid, it should be understood that the disclosed hydraulic lift system is similarly applicable to recover other well fluids such as hydrocarbon or water. 
     As shown, the apparatuses and methods of the present disclosure provide improved hydraulic power systems and acoustic controls to overcome the limitations of conventional lift systems, such as positive displacement pumps on the surface of the earth used to power submersible hydraulic motors, engines, turbines, pumps, compressors, and other submersible fluid transducers. 
     In particular, the present disclosure provides power fluid pumps, such as pump  409  of  FIG. 4  and pump  510  of  FIG. 5 , that are non-piston pumps, non-positive displacement, pumps. In addition, the present disclosure provides placing the improved hydraulic powering pumps below the surface. The methods and apparatuses of the present disclosure apply to powering all submersible hydraulic transducer systems including compressors, and pumps and also have applications in water wells, in addition to oil and gas wells. The methods and apparatuses of the present disclosure can include submersible hydraulically driven piston pumps, progressive cavity pumps, centrifugal pumps, jet pumps, and other pumps that are used to lift well fluids from subterranean reservoirs. The present disclosure provides methods and apparatuses that address the limitation of using water in cold climates. In one embodiment, both the power fluid discharge, produced fluid, and fluid separation are kept below the surface to keep the fluid warm. 
     The present disclosure also provides for encapsulation of the improved hydraulic system by housing of the hydraulic power supply system within a caisson or a casing below the surface. The electrical submersible pump system is configured to discharge high pressure hydraulic power fluid to a well or a plurality of oil and gas production wells having submersible hydraulic fluid pumps disposed in them. The hydraulic power pumping system of the present disclosure powers submersible hydraulic motors, engines and pumps below the surface, thereby addressing safety, environmental, aesthetic, and cold temperatures limitations of conventional systems. 
     Although the present invention and its advantages have been described in detail, it should be understood that various changes, substitutions and alterations can be made herein without departing from the spirit and scope of the invention as defined by the appended claims. Moreover, the scope of the present application is not intended to be limited to the particular embodiments of the process, machine, manufacture, composition of matter, means, methods and steps described in the specification. As one of ordinary skilled in the art will readily appreciate from the disclosure of the present invention, processes, devices, manufacture, compositions of matter, means, methods, or steps, presently existing or later to be developed that perform substantially the same function or achieve substantially the same result as the corresponding embodiments described herein may be utilized according to the present invention. Accordingly, the appended claims are intended to include within their scope such processes, devices, manufacture, compositions of matter, means, methods, or steps.