Patent Publication Number: US-7717181-B2

Title: Artificial lift system

Description:
BACKGROUND 
   Subterranean wells have been drilled primarily to produce one or more of the following desired products for example fluids such as water, hydrocarbon liquids and hydrocarbon gas. There are other uses for wells but these are by far the most common. These desired fluids can exist in the geologic layers to depths in excess of 5,000 m below the surface and are found in geological traps called reservoirs where they may accumulate in sufficient quantities to make their recovery economically viable. Finding the location of the desirable reservoirs and drilling the wells present their own unique challenges. Once drilled, the wellbore of the well must be configured to transport safely and efficiently the desired fluid from the reservoir to surface. 
   Whether or not the desired fluid can reach surface without aid is a function of numerous variables, including: potential energy of the fluid in the reservoir, reservoir driver mechanisms, reservoir rock characteristics, near wellbore rock characteristics, physical properties of the desired fluid and associated fluids, depth of the reservoir, wellbore configuration, operating conditions of the surface facilities receiving fluids and the stage of the reservoirs depletion. Many wells in the early stages of their producing life are capable of producing fluids with little more than a conduit to connect the reservoir with the surface facilities, as energy from the reservoir and changing fluid characteristics can lift desired fluids to surface. 
   Typically fluids in a liquid phase cause the most problems when attempting to move the fluids vertically up the wellbore. Fluids in the liquid phase are much denser than fluids in a gaseous phase and therefore require greater energy to lift vertically. These fluids in the liquid phase can enter the wellbore in the liquid state as free liquids or they can enter the wellbore in the gas phase and later condense into liquid in the wellbore due to changing physical conditions. The liquids that enter the wellbore may be desirable fluids, such as hydrocarbon liquids or useable water, or they may be liquids associated with the desired fluids, for example, water produced with oil or gas. Often the liquids associated with the desired fluids must be produced in order to recover the desired fluid. Regardless of the desirability of the liquid, energy is required to transport the liquid vertically from the reservoir to surface. Optimizing the energy required through improved wellbore dynamics or with the aid of artificial lift has been an area of intense study and literature for those dealing with subsurface wells. 
   To improve the economics of a well, it is desirable to increase the production rate and maximize the recovery of the desired fluid from the well. Transportation of fluids from reservoir to surface, that is well bore dynamics, is one of the variables of the well that can be controlled and has a major impact on the economics of a well. One can improve the well bore dynamics by two methods—1) designing a wellbore configuration that optimizes and improves the flow characteristics of the fluid in the well bore conduit or 2) aiding in lifting the fluid to surface with artificial lift. Artificial lift can significantly improve production early in the life of many wells and is the only options for wells if they are to continue producing in the later stages of depletion. Regardless of whether the well can lift the desired fluids to surface on its own or requires artificial lift, the well bore dynamics should be reviewed continually as the variables change over the life of the well and the economics for the well need to be maximized. 
   The methods of improving flow characteristics include: proper tubing selection, plunger systems, addition of surface tension reducers, reduced surface pressures, downhole chokes and production intermitters. These methods do not add energy to the fluids in the well bore, and therefore are not considered artificial lift systems; however, they do optimize the use of the energy that the reservoir and fluids provide. These methods optimize the well bore dynamics and/or add energy to the fluid transportation process at the surface. Depending on the application, each of the different methods above has numerous models and configurations each having their own unique advantages and disadvantages. 
   There are numerous systems of artificial lift available and operating throughout the world. The more common systems are reciprocating rod string and plunger pumps, rotating rod strings and progressive cavity pumps, electric submersible multi-stage centrifugal pump, jet pumps, hydraulic pumps and gas lift systems. Again, depending on the intended application, each of the different systems has numerous models each having their own unique advantages and disadvantages. To fit in the category of artificial lift, additional energy not from the producing formation and fluids is input into the well bore to help lift fluids in the liquid phase to surface. The artificial lift systems listed above have been developed for water and hydrocarbon liquids as they require the greatest assistance when being transported to surface and provide the greatest economic incentive. They also have applications in lifting liquids that are associated with the gas in natural gas wells. 
   With the depletion of the world gas reserves there is a need to develop an artificial lift system that is better suited to removing liquids associated with natural gas production from the wellbore. These liquids, if not removed from the wellbore, will significantly limit the natural gas production rates as wells as the ultimate recovery of the natural gas reserves. 
   Other artificial lift systems have been designed and used based on injection of high-pressure gas. Gas lift is a common form of artificial lift and relies on injection of enough gas to reach the critical rate for removing liquids from the wellbore (Turner et al in 1969: Turner, R. G., Hubbard, M. G., and Dukler, A. E., 1969, “Analysis and Prediction of Minimum Flow Rate for the Continuous Removal of Liquids from Gas Wells,” J. Pet. Technol., 21(11), pp. 1475-1482.) 
   U.S. Pat. No. 5,211,242 by Malcolm W Coleman and J Byron Sandel outlines the complete removal of fluids from the well on each cycle, which requires large gas volume and therefore large associated equipment with pumping, for example large tubing, a large compressor, large power source valves, etc. 
   There is a need for pumps that can be installed and serviced without the use of a service rig using wireline or coiled tubing equipment and techniques, to allow for easy installation and servicing. There is a need for pumps that fit with existing technologies, services and equipment, and may fit with existing wellbore configurations with only minor modifications. 
   SUMMARY 
   In an embodiment there is an artificial lift system, comprising a gas compressor, a gas pump seated downhole in a well and a power conduit. The power conduit extends along the well and provides a fluid connection between the gas pump and the gas compressor. 
   In an embodiment there is an artificial lift system comprising a downhole pump, a power conduit connected to the gas pump and a downhole release mechanism between the power conduit and the downhole pump. 
   In an embodiment there is a method of installing a downhole pump in a well, the method comprising the steps of connecting a downhole pump to coil tubing and lowering the downhole pump into the well. 
   In an embodiment there is a method of removing an artificial lift system from a wellbore, comprising the steps of disconnecting a power conduit from a downhole pump, pulling the power conduit from the wellbore and pulling the downhole pump from the wellbore. 

   
     BRIEF DESCRIPTION OF THE FIGURES 
     Embodiments will now be described with reference to the figures, in which like reference characters denote like elements, by way of example, and in which: 
       FIG. 1  is a section view of a wellbore showing the producing formation; 
       FIG. 2  is a section view of an embodiment of downhole components of a wellbore showing the production formation; 
       FIG. 3  is a side view showing an embodiment of the installation of a gas pump in a wellbore; 
       FIG. 4  is a side view showing an embodiment of the surface components of a gas pump; 
       FIG. 5  is a section view of an embodiment of a downhole release mechanism; 
       FIG. 6  is a section view of an embodiment of a downhole valve body; and 
       FIG. 7A ,  FIG. 7B ,  FIG. 7C  and  FIG. 7D  are sectional views of the embodiment of a downhole valve body of  FIG. 6  along the lines A, B, C, and D, respectively. 
   

   DETAILED DESCRIPTION 
   In the claims, the word “comprising” is used in its inclusive sense and does not exclude other elements being present. The indefinite article “a” before a claim feature does not exclude more than one of the feature being present. 
     FIG. 1  is an embodiment of a wellbore showing a reservoir  15 , a drilled hole from surface to the producing formation, a liquid conduit  23 , including casing  10  and tubing string  9  that safely transport the producing fluids from the reservoir to surface. Also included in the drawing is the equipment associated with the pump: a downhole pump  12 , small diameter continuous tubing string  8 , a compressor unit  2  and a logic controller  4 . The small diameter continuous tubing string  8  is also called a power conduit, a power fluid conduit or small diameter continuous tubing. 
   In an embodiment, an artificial lift system uses high pressure dry gas  1 A as the power fluid to pump liquids from the bottom of gas wells, therefore allowing gas to flow unrestricted to surface, for example, the gas may flow to the surface unrestricted by liquid build up in the wellbore. In doing so the production rate of the gas can be increased and additional reserves recovered. 
     FIG. 1  shows an embodiment of the device, in which a downhole pump  12  is driven by high pressure gas from the surface. High pressure dry gas  1 A is injected down a dedicated small diameter continuous tubing  8  into a pump pressure chamber  18  at the bottom of the well expelling any liquid present in the pump pressure chamber  18  through an exit check valve  19  and out of a liquid discharge port  24  at the top of the downhole pump  12 . After the liquid in the pump pressure chamber  18  has been expelled, the pressure in the pump pressure chamber  18  is bled off. When depressurized, liquid from the bottom of the wellbore  17  is allowed to enter the pump pressure chamber  18  through the check valve  21  on an inlet screen  22  at the bottom of the downhole pump  12 . To achieve maximum efficiency the pump pressure chamber  18  is allowed sufficient time to completely fill with liquid and to completely expel that liquid before the cycle repeats itself. 
   In order to recover the desired fluids from a reservoir  15 , casing  10  and tubing string  9  are run in the well for the safe and efficient transportation of a desired fluid from the reservoir to the surface facilities  7  using acceptable oilfield designs. Initially, the reservoir fluids often have sufficient energy in the form of pressure to transport the desired fluids and associated fluids from the reservoir  15  to the bottom of the wellbore  17 , and then from the bottom of the wellbore  17  to the surface facilities  7  without the aid of artificial lift equipment. However, once a well has reached a stage of depletion where there is insufficient energy available to transport the fluids vertically to surface the economics may justify the addition of artificial lift. Artificial lift aids in the vertical transportation of the fluids in the liquid phase from the bottom of the wellbore  17  to the surface facilities  7 . Typically the fluids in the liquid and gas phases are allowed to separate in the bottom of the wellbore  17 . Due to density differences, since liquids are of much higher densities, the fluids in the liquid phase drop to the bottom of the wellbore  17  where they can be pumped to surface facilities  7  up the small diameter continuous tubing  8  by the artificial lift equipment. The fluids in the gas phase require much less energy to be transported vertically up the wellbore when the liquids are not interfering with this transportation. The fluids in the gas phase are allowed to flow up a tubing annulus  29  unrestricted by the fluid in the liquid phase. 
   For description purposes an embodiment of a downhole pump in a wellbore has been broken into three main components: surface equipment, a wellbore conduit and a downhole pump. 
   A compressor unit  2  comprises a gas dryer, a high pressure compressor coupled with a drive unit, an accumulator (not shown), a logic controller  4 , a surface fill valve  3  and a surface bleed valve  5 . This equipment provides a power fluid, for example a high pressure dry gas  1 A, necessary to operate the downhole pump  12 . The compressor unit  2  takes natural gas from the well or other desired source  1  and removes any contaminants including water. After cleaning the gas it is compressed to the desired operating pressure for the downhole pump  12  and stored in the accumulator until required to operate the pump. The operating pressure is the sum of the hydrostatic pressure of the liquid column between surface and the downhole pump  12 , the pressure of the surface equipment the liquid is being discharged into, and the desired preset pump activation pressure that insures efficient operation of the pump. The accumulator is connected to the small diameter continuous tubing  8 , through a surface fill valve  3 . Downstream of the surface fill valve  3  there is a surface bleed valve  5 . These valves are controlled by the logic controller  4  which open and closes the valves for the different stages of the pumping cycle. 
   A power fluid conduit  8  comprising small diameter continuous tubing runs from the compressor unit  2  to the downhole pump  12 . The power fluid conduit  8  delivers the power fluid  1 A from the compressor unit  2  to the downhole pump  12  during the pressurization stage and from the downhole pump  12  to the surface facilities  7  during the depressurization stage. 
     FIG. 2  shows an embodiment of the device in which a downhole pump  12  comprises a number of parts required for operation and serviceability of the pump. At the top of the downhole pump  12  is a connector head  30  which connects, releases and seals the power fluid conduit  8  to the downhole pump  12 . Below the connector head  30  is a pump seating assembly  31  which comprises: an internal fish neck  78  ( FIG. 5 ) for setting and retrieving the pump, the liquid discharge port  24 , a NoGo ring  88  ( FIG. 5 ) to hold the pump in position, an external seal pack  90  ( FIG. 5 ) to isolate the liquid conduit  23  from the bottom of the wellbore  17 , a connection between the connector head  30  and the pump pressure chamber  18  for the power fluid and a primary equalizing port  72  ( FIG. 5 ) for pulling of the pump. Below the pump seating assembly  31  is a pump pressure chamber connector  32  with the connection between the pump pressure chamber  18  and the power fluid conduit  8  directly or via the downhole fill valve  100  ( FIG. 6 ) and downhole bleed valve  28  and the connections from the liquid exit tube  26  to the liquid discharge port  24  on the pump seating assembly  31 . The downhole fill valve  100  ( FIG. 6 ) and downhole bleed valve  28  work together and as an assembly is also called a three way valve  28 ,  100 . Below the pump pressure chamber connector  32  is the pump pressure chamber  18  which acts as a receptacle for liquids on the intake stage and a pressure chamber on the discharge stage of the pumping cycle and the liquid exit tube  26  is inside the pump pressure chamber  18  connecting an exit check valve  19  on the bottom of the liquid exit tube  26  to the liquid discharge port  24  on the pump pressure chamber connector  32 . On the bottom of the downhole pump  12  is an inlet check valve  21  and an inlet screen  22 . 
   In an embodiment, a downhole pump  12  is run in a wellbore hole on small diameter continuous tubing  8  using a conventional wireline unit having a drawworks or specially built coiled tubing unit. The downhole pump  12  has a NoGo ring  88  ( FIG. 5 ) and an external seal pack  90  ( FIG. 5 ) that seat in a profile  13  at the bottom of the well that is part of the existing tubing string  9 . Landing the downhole pump  12  in the profile  13  holds the downhole pump  12  in place and also seals the small diameter continuous tubing  8  inside a liquid conduit  23  above the profile  13  separate from the bottom of the wellbore  17 . Once in place, the small diameter continuous tubing  8  acts as the conduit to deliver high pressure dry gas  1 A to the pump pressure chamber  18  and acts as a conduit to bleed off the pump pressure chamber  18  once liquids have been expelled from the pump pressure chamber  18 . The annular area between the small diameter continuous tubing  8  and the existing tubing string  9  act as the liquid conduit  23  to deliver the liquid expelled from the liquid discharge port  24  to surface facilities  7 . The downhole pump  12  has two check valves, one at a inlet check valve  21  where liquid from the bottom of the wellbore  17  enters the pump pressure chamber  18  and one at an exit check valve  19  where liquids are expelled from the pump pressure chamber  18  into the liquid exit tube  26  and then into the liquid conduit  23 . 
   In an embodiment, there are three stages in a pumping cycle; the first stage starts with the pump pressure chamber  18  depressurized to a pressure below the pressure external to the intake check valve  21 . 
   In the first stage of the pump cycle time is allowed for fluids external to the pump pressure chamber  18 , for example at the bottom of the wellbore  17 , to flow into the pump pressure chamber  18  through the inlet check valve  21 . 
   In the second stage of the pump cycle time is allowed for the compressor unit  2  and accumulator to supply high pressure dry gas  1 A at a sufficient pressure down the power fluid conduit  8  to the pump pressure chamber  18  to expel the liquid from the pump pressure chamber  18  through the exit check valve  19  into the liquid exit tube  26  and then out the liquid discharge port  24  into the liquid conduit  23 . 
   In the third stage of the pump cycle time is allowed for the depressurizing of the pump pressure chamber  18  which can be done in multiple ways. Two exemplary embodiments for methods of depressurizing the pump pressure chamber are as follows: 
   In an embodiment of one method the gas pressure  1 B is bled back to surface facilities  7  through the power fluid conduit  8  and surface bleed valve  5 . This approach of bleeding off pump pressure chamber  18  and power fluid conduit  8  reduces efficiency and pump capacity but is mechanically simple and therefore is often applicable in shallower wells. 
   In an embodiment of a second method a pressure activated downhole fill valve  100  ( FIG. 6 ) and downhole bleed valve  28  are installed. This second method allows for a more efficient pump operation by only bleeding off a small amount of the gas pressure  1 B from the power fluid conduit  8 . When the power fluid conduit  8  is pressured up above the set point of the three way valve set point the power fluid conduit  8  and the pump pressure chamber  18  are in communication and the pump pressure chamber  18  is isolated from the downhole bleed port  27  allowing pump pressure chamber  18  to be pressurized. When the power fluid conduit  8  is bled off to below the set point of the three way valve  28  &amp;  100  ( FIG. 6 ) the power fluid conduit  8  is isolated from the pump pressure chamber  18 , at the same time the pump pressure chamber  18  and the downhole bleed port  27  are in communication allowing the pump pressure chamber  18  to be depressurized. 
   The third stage is the final stage in the pump cycle. All the stages may be controlled by a logic controller  4  using time and/or pressure and are adjusted based on the application requirements. 
   Now installation and removal of an embodiment of an artificial lift system will be described. 
   In an embodiment, to ensure a cost effective installation and positive working results one must first review and analyze the working conditions of the well. This includes gathering information on the configuration of the wellbore, such as casing size, tubing size and depth, type and location of profiles in tubing string, type and location of packer that may isolate a tubing annulus, depth of perforations and restriction and/or objects that may interfere with the running of the pump in the well. Fluid characteristics should also be determined—gas density, water density and hydrocarbon liquid density along with their expected production rates. Pressures and temperatures at the pump intake and surface outlet must also be determined through measurement or estimated. Once gathered, this information can be used to calculate the desired configuration of the equipment and operating parameters. 
   In an embodiment, an artificial lift system is designed to work with existing wellbore equipment and configurations but if the existing wellbore configuration is less than optimum for pumping liquids it may need to be modified. As an example, a possible wellbore configuration is as follows: production depth of the well not greater than 3000 m, clean 60 mm tubing string or larger, one profile located at bottom of the perforations or lower, no tailpipe below the profile or a 6 mm hole  33  in tailpipe immediately below profile, 5 m of clean cased hole below bottom of perforations, no packer in hole that would restrict flow up the tubing annulus. Such a wellbore configuration is very similar to that of the common oilwell rod pump installation; where the liquids are pumped up the tubing string and the gas flows up the tubing annulus. However in this design, instead of a rod string being run inside the existing tubing string, the rods are replaced by the small diameter continuous tubing  8  that delivers high pressure gas  1 A to drive the pump which is a pump pressure chamber  18  rather then a plunger style pump. Existing wellheads may be utilized by installing a production blowout preventer (BOP)  40  ( FIG. 3 ) into the top of the existing flow tee. The production BOP  40  ( FIG. 3 ) provides the primary seal around the small diameter continuous tubing  8 . Above the production BOP  40  ( FIG. 3 ) is a device to suspend the small diameter continuous tubing  8  in the well and above this device there is a pack-off  45 A ( FIG. 4 ) to provide a secondary seal around the small diameter continuous tubing  8 . The existing master valves will need to be locked open to prevent damage to the small diameter continuous tubing  8 . In an emergency the master valves could be shut, cutting the small diameter continuous tubing  8  to shut-in the well. 
   In an embodiment, once a wellbore has been configured for pumping conditions and pumping equipment has been selected, the artificial lift system can be constructed for the application and surface tested. The downhole pump  12  is run in the hole on the small diameter continuous tubing  8  using the drawworks of conventional wireline or coiled tubing methods and equipment. A variety of equipment may be used as a lift unit to run and pull the pump, such as an electric line unit, a braided line unit, a slickline unit, a wireline unit and a logging unit. The pump can be run down the existing tubing string  9  under pressure conditions or with the existing tubing string  9  in a killed state. To run in under pressure one can use conventional wireline or coiled tubing BOPs, lubricator, grease injector and pack-off equipment following wireline or coiled tubing procedures. The downhole pump  12  and small diameter continuous tubing  8  are run in the hole to the depth where the pump seating assembly  31  is landed in the profile  13 . First the external seal pack  90  ( FIG. 5 ) on the external diameter of the pump seating assembly  31  are landed in the sealing section of the desired profile  13  ( FIG. 1 ) and the production BOP  40  ( FIG. 3 ) and service BOP  44  ( FIG. 3 ) on top of the wellhead are closed around the small diameter continuous tubing  8 . Then the liquid conduit  23  may then be filled with water and the tubing, external seal pack  90  ( FIG. 5 ) and production BOP  40  and service BOP  44  ( FIG. 3 ) may be pressure tested. After proving the integrity of the components the small diameter continuous tubing  8  is hung off at surface and the pack-off  45 A ( FIG. 4 ) is installed. The small diameter continuous tubing  8  is then detached or cut off and a valve  45 B ( FIG. 4 ) is installed on the end of the small diameter continuous tubing, disconnecting it from the unit which ran it into the well. Cutting the small diameter continuous tubing off and installing the valve  45 B, makes it possible to connect the small diameter continuous tubing  8  to the compressor unit  2 . 
   In an embodiment, once the downhole pump  12  and power fluid conduit  8  are installed the power fluid conduit  8  can be connected to a compressor unit  2 . Cycle times and pressure settings calculated in the pump configuration program are input into the logic controller  4 . To start the pump, the power fluid conduit  8  and the pump pressure chamber  18  are pressurized to the desired operating pressure. During the pressurization stage the pressure in the power fluid conduit  8  will activate the three way valve  28  &amp;  100  ( FIG. 6 ) in the top of the downhole pump  12  at the set pressure of the three way valve  28  &amp;  100  ( FIG. 6 ), closing the downhole bleed port  27  and opening the pump pressure chamber  18  to the power fluid conduit  8 . Once the required operating pressure has been reached in the pump pressure chamber  18 , liquid in the pump pressure chamber  18  is expelled through the exit check valve  19  into the liquid exit tube  26 , out the downhole pumps liquid discharge port  24  and into the liquid conduit  23 . No backflow will be allowed due to the exit check valve  19 . Once the appropriate time has passed to expel liquid from the pump pressure chamber  18 , the timer will close the surface fill valve  3  and open the surface bleed valve  5 . At this point the bleed down cycle will begin. During the bleed down cycle, gas is bled from the power fluid conduit  8  at surface through the surface bleed valve  5  to the flowline. To monitor the pump operation, a surface liquid conduit valve  38 C should remain closed until the desired increase in pressure is observed. A number of pump cycles may be required to see the desired pressure response. Depending on the downhole pump  12  configuration, downhole three way valve installed or no downhole three way valve installed, the timing on the bleed down stage of the pump cycle will need to be configured appropriately. 
   For the downhole three way valve configuration: the pressure on the power fluid conduit  8  is reduced, until it is below the pressure set point to actuate the downhole three way valve. The three way valve closes the pressure chamber depressurization port  110  ( FIG. 6 ) which connects with the pump pressure chamber  18  and opens the downhole bleed port  27  allowing the pump pressure chamber  18  to bleed off to the area external to the pump below the downhole pump sealing profile  13 . Once sufficient time has passed to allow the pump pressure chamber  18  to fully depressurize additional time is allowed for the pump pressure chamber  18  to fill completely with liquid. Once filled completely with liquid the next pump pressurization stage begins. To control the rate at which liquid is pumped from the well, the times allowed for stage  3  &amp;  2  can be adjusted. The times for these stages must remains above the calculated minimum times required to depressurize and fill the pump pressure chamber  18 . 
   For the no downhole three way valve configuration: the pressure on the power fluid conduit  8  is reduced until it is below the bottomhole flowing pressure of the well. Here typical pipeline flowing pressure may be used. Once sufficient time has passed to allow the pump pressure chamber  18  to fully depressurize additional time is allowed for pump pressure chamber  18  to fill completely with liquid. Once filled completely with liquid, the next pump pressurization stage begins. To control the rate at which liquid is pump from the well, the times allowed for stage  3  &amp;  2  can be adjusted. The times for these stages must remains above the calculated minimum times required to depressurize and fill the pump pressure chamber  18  with liquid. 
   To pull the artificial lift system one must release or cut the power fluid conduit  8  immediately above the internal fish neck  78  ( FIG. 5 ) and pull the small diameter continuous tubing  8  out of the well. The small diameter continuous tubing  8  is not normally strong enough to pull the downhole pump  12  out of the well. Prior to pulling the downhole pump  12  the pressure above the downhole pump  12  must be equalized with the pressure below the downhole pump  12 . This is done by removing some of the liquid from the liquid conduit  23 . This can occur automatically if the primary equalization port  72  is not plugged, allowing liquids above pump to drain back into the bottom of the wellbore  17  once the connecting head is released  62 . If it is undesirable to allow liquids to drain back into the bottom of the wellbore  17  the primary equalization port  72  may be plugged and the use of conventional swab equipment and techniques to remove the liquid from the liquid conduit may be employed. Swabbing the tubing minimizes the fluid that drains back into formation once the equalizing plug of the downhole pump has been broken off. As a backup if primary equalization port  72  becomes plugged or swabbing is unable to be performed the liquid may be drained through the backup equalizing port  74  by running in the hole with slickline tools, break off the equalizing plug inside the internal fish neck  78  ( FIG. 5 ) on the downhole pump  12  allowing the liquids above the downhole pump to drain back into the well below the sealing profile at the bottom of the wellbore  17 . After equalizing the pressure above and below the downhole pump  12 , run in with wireline equipment with sufficient line size and tool configuration to unseat the gas pump and pull the gas pump to surface and latch on to the internal fish neck  78  ( FIG. 5 ) and pull downhole pump  12  to surface. 
   Once the downhole pump  12  has been pulled from well, the downhole pump  12  can be repaired and reinstalled or other activities conducted on well as desired using normal oilfield procedures. 
   In an embodiment shown in  FIG. 3 , an artificial lift system makes use of conventional electric line and slickline methods and equipment, making installing and removal of the artificial lift system effective, quick and safe. A conventional electric line or slickline unit  34  is placed approximately 50 ft from an existing wellhead  38  and a crane unit  36  is placed next to the wellhead  38 . Other orientations of the slickline unit  34  and crane unit  36  will also work. Other suitable equipment for running and pulling an artificial lift system may alternatively be used. The conventional slickline unit  34  installs small diameter coiled tubing  8  on cable or wire draw workings. The small diameter coiled tubing  8  replaces the conventional cable or wire. In an embodiment the wellhead  38  comprises a top master valve  38 A, a flow tee  38 B and a wing valve  38 C. 
   To install, sections of lubricator  46  are laid out on ground stands and which when connected together are of sufficient length to enclose a complete artificial lift system  60  assembly. In the embodiment shown in  FIG. 3 , the artificial lift system  60  is hanging in the lubricator sections  46  prior to running in hole. In an embodiment, the sections of lubricator  46  are used to contain pressure while running and pulling the artificial lift system  60  from the well. The sections of lubricator  46  could be, for example, a lubricator section of Bowen type such as PN 14339. A service BOP  44  is connected to the bottom of the lubricator sections. The service BOP  44  is installed for running and pulling the artificial lift system  60 . The service BOP  44  could be, for example, a service BOP of Bowen type such as PN 57678. The bottom of the artificial lift system  60  is inserted into the top of the lubricator sections  46 . 
   Some of the power conduit  8  is spooled out from the slickline unit  34  and the power conduit is threaded through a top block assembly  50  combined with a pack-off  48 . A make up connection is used between the power conduit  8  and the downhole release mechanism  76 , an embodiment of which is shown in  FIG. 5 . 
   Next, the top block assembly  50  combined with pack-off  48  is installed to the top of lubricator sections  46 . The top block assembly  50  redirects the path of the small diameter coiled tubing  8  and supports the weight of the small diameter coiled tubing  8  as well as the weight of an artificial lift system assembly, comprising the artificial lift system  60 , attached to the end of the small diameter coiled tubing  8 . The top block assembly  50  could be, for example, a top block of Bowen type, such as PN 44677. The downhole release mechanism  76  is connected to the artificial lift system assembly that was inserted in the top of the lubricator sections  46 . After the downhole release mechanism  76  is connected to the artificial lift system assembly, the artificial lift system  60  is pushed completely into the lubricator sections  46  and the top block assembly  50  is connected to the top of the lubricator sections  46 . A cap (not shown) is inserted on the bottom of the service BOP  44  to ensure the artificial lift system assembly does not fall out the bottom when it is raised. 
   Next, the wellhead is prepared for being connected to the lubricator sections  46 . A pressure reading is taken. The top master valve  38 A and the wing valve  38 C are both closed. The pressure trapped between these two valves is bled to 0 psig using the flow tee  38 B bleed valve. The cap (not shown) is removed from the flow tee  38 B and a production BOP  40  is installed into the internal connection of the flow tee  38 B. In an embodiment, the production BOP  40  comprises a modified sucker rod BOP with rams modified to seal on the small diameter coiled tubing  8 . An adaptor nipple  42  is installed into the top of the production BOP  40 . The adapter nipple  42  connects the production BOP  40  to the service BOP  44 . 
   Next the lubricator sections  46  is prepared for being connected to the wellhead. A top block support cable  56  is installed between the top block assembly  50  and a crane hoisting cable hook  92 . A pack-off  48  with the power conduit  8  threaded through is attached to the lubricator sections  46 . The top block support cable  56  supports the weight of and stabilizes the movement of the power conduit  8 , the artificial lift system  60 , the top block assembly  50 , the pack-off  48  and the lubricator section  46 . The top of lubricator section  46  is lifted until lubricator sections  46  are hanging vertical. The power conduit  8  may need to be spooled out at the same time so that it does not get damaged as the lubricator sections  46  are lifted. A bottom block  52  and a tie down cable  54  are installed. The power conduit  8  is threaded through the bottom block  52 . The bottom of the lubricator sections  46  is positioned directly over the wellhead. The bottom block  52  redirects the path of the small diameter coiled tubing  8  and supports the weight of the small diameter coiled tubing  8  as well as the weight of the pump assembly attached to the end of the small diameter coiled tubing  8 . The bottom block  52  assembly could be, for example, a bottom block of Bowen type, such as PN 14414. The lubricator sections  46  when assembled together comprise a lubricator assembly. 
   The power conduit  8  is spooled so that slack in the power conduit  8  is removed and the artificial lift system is no longer resting on the cap (not shown) on the bottom of the service BOP  44 . The cap (not shown) is removed from bottom of service BOP  44 . In an embodiment, the artificial lift system  60  is lowered out the bottom of the lubricator assembly  46  to a measurement datum and a depth counter is adjusted appropriately. The artificial lift system  60  is raised into the lubricator assembly  46  and lubricator assembly  46  is lowered onto the top of the wellhead and the connection is made. The lubricator assembly  46  is then pressure tested to the appropriate pressure. 
   At this point, the artificial lift system  60  is ready to run in the hole. The top master valve  38 A is opened. The artificial lift system  60  is run down to a desired depth. The artificial lift system landing assembly is landed in a desired profile  13  ( FIG. 1 ) in the well. Thus, the artificial lift system  60  and the power conduit  8  are now in place. A pressure test can be carried out to ensure that no leaks are present in the power conduit  8  or the liquid conduit  23  ( FIG. 1 ). 
   In an embodiment, handles on the top master valve  38 A and bottom master valves are locked and warning signs are installed to warn against the operation of the valves. The production BOP  40  is closed and the pressure is bled from the lubricator assembly  46  to 0 psig. 
   The adaptor nipple  42  is disconnected from the bottom of the lubricator assembly and the lubricator assembly  46  is raised. Approximately 200 feet of power conduit  8  is pulled down through the lubricator assembly  46  and the power conduit  8  is cut off at the bottom of lubricator assembly  46 . Other lengths of power conduit  8  may be pulled down through the lubricator assembly  46 . 
   In an embodiment of the installation shown in  FIG. 4 , a production BOP  40  is connected to the top of the wellhead which comprises a top master valve  38 A, a flow tee  38 B and a wing valve  38 C. A production pack-off  45 A is connected to the top of the production BOP  40 . A length of surplus power conduit  45 C, for example, approximately 200 feet long, is coiled and a valve  45 B lies on the end of the surplus power conduit  45 B. 
   The surplus power conduit  45 C must remain attached and will be required for the pulling operation. The adaptor nipple  42  ( FIG. 3 ) is removed from the production BOP  40  and a production pack-off  45 A is installed on top of the production BOP  40 . The 200 feet of surplus power conduit  45 C protruding from top of the production pack-off  45 A is coiled and a valve  45 B is installed on the end of the surplus power conduit  45 C. 
   After installation of the artificial lift system, the slickline unit  34  ( FIG. 3 ), the crane unit  36  ( FIG. 3 ) and associated equipment are rigged out. Surface equipment associated with the artificial lift system  60  ( FIG. 3 ) is installed and pump operation is started. 
   An embodiment of a downhole release sub  62  is shown in  FIG. 5 . The downhole release sub  62  comprises a downhole release mechanism  76  and a downhole pump connector  86  being releasably attached to the downhole release mechanism  76 . The downhole release mechanism  76  is an embodiment of the connector head  30  shown in  FIG. 1 . The downhole pump connector  86  is an embodiment of the pump seating assembly  31  shown in  FIG. 1 . A power conduit  8  is attached at one end to the downhole release mechanism  76 . A power fluid extension prong  68  is attached to the base of the downhole release mechanism  76 . A connection fitting  64  attaches the power conduit  8  to the downhole release mechanism  76 . The downhole pump connector  86  is releasably attached to the downhole release mechanism  76  by breakable fastenings, such as release shear pins  66 . A chamber  96  lies between the downhole release mechanism  76  and the downhole pump connector  86 . The chamber  96  is pressure sealed with pressure seals  70  which lie below the release shear pins  66 . A pressure release mechanism, such as release equalizing stem  94 , lies between the downhole pump connector  86  and the downhole release mechanism  76  and provides a fluid connection between the exterior of the downhole release mechanism  76  and the chamber  96 . 
   An external fish neck lies at the top of the downhole release mechanism  76  where the power conduit  8  connects to the downhole release mechanism  76 . A fish neck, for example internal fish neck  78 , is attached to the top of the downhole pump connector  86 . Below the chamber  96  is a liquid discharge port  24  at the end of liquid exit tube  26 . Below the liquid discharge port  24  is a NoGo ring  88 . At some point below the NoGo ring  88  is an external seal pack  90 . A primary equalizing port  72  lies on the exterior of the downhole pump connector  86 . Pressure seals  71  seal the power fluid extension prong  68  from the primary equalizing port. A backup equalizing port  74 , as shown in  FIG. 5 , may also be present if additional equalizing ports are necessary. A connection interface, such as threading  84 , lies on the base of the downhole pump connector  86 . 
   The downhole release mechanism  76  is designed to release the power conduit  8  from the downhole pump after an application of external pressure on both the power conduit  8  and the downhole release mechanism  76  that is sufficient to break breakable fastenings, such as release shear pins  66 . Pressure is applied to the area exterior to the power conduit  8  defined by the liquid conduit  23 . The release shear pins  66  are to be sized so as not to release under normal operating condition yet shear below safe operating limits of the liquid conduit  23  ( FIG. 1 ) and the wellhead. The pressure seals  70  maintain fluid pressure between the chamber  96  and a liquid conduit ( FIG. 1 ) exterior to the downhole release mechanism  76 . Power fluid is pumped down the power conduit  8  through the power fluid extension plug  68  into the pump pressure chamber  18  ( FIG. 1 ) below the downhole release mechanism  76 . Production fluid that is returning to surface from the pump pressure chamber  18  ( FIG. 1 ) passes through the liquid exit tube  26  and through the liquid discharge port  24  into the liquid conduit  23  ( FIG. 1 ). The pump pressure chamber  18  ( FIG. 1 ) may be connected, for example by threads  84 , to the base of the downhole pump connector  86 . In an embodiment the downhole pump connector  86  may sit on the profile NoGo ring  88  in a seat in the profile  13  ( FIG. 1 ) of the wellbore. 
   Once sheared, the downhole release mechanism  76  can be pulled apart from the internal fish neck  78  on the artificial lift system which in turn opens a primary equalizing port  72  connecting the liquid conduit  23  ( FIG. 1 ) and the bottom of the wellbore  17  ( FIG. 1 ). Pressure seals  71  maintain fluid pressure around the primary equalizing port  72 . In an embodiment, the backup equalizing port  74  may also be used to equalize the pressure between the liquid conduit  23  ( FIG. 1 ) and the bottom of the wellbore  17  ( FIG. 1 ). When the power fluid extension prong  68  is removed from the wellbore the primary equalizing port  72  supplies a direct connection between the bottom of the wellbore  17  ( FIG. 1 ) and the chamber  96 . After the removal of the downhole release mechanism  76 , the chamber  96  lies within the liquid conduit  23  ( FIG. 1 ). Alternatively, the primary equalizing port  72  may be plugged if draining of fluid back into the bottom of wellbore  17  ( FIG. 1 ) is undesirable. The release equalizing stem  94  equalizes the pressure in a chamber  96  lying between the downhole release mechanism  76  and the internal fish neck  78  with the pressure lying exterior to the chamber  96 . Other methods of releasing the residual pressure in the artificial lift system and the downhole release mechanism  76  may also be used provided that pressures in the wellbore are sufficiently equalized to allow the downhole release mechanism  76  to be pulled from the wellbore. The power conduit  8  and the downhole release mechanism  76  can be pulled from the wellbore once released. The external seal pack  90  sits below the NoGo ring  88  and the wellbore profile  13  ( FIG. 1 ). 
   An embodiment of a downhole valve body  98  is shown in  FIG. 6 . A downhole valve body  98  is designed to provide power fluid to the pump chamber by a pressure actuated gas lift valve  100 . The downhole valve body  98  is an embodiment of the pump pressure chamber connector  32  shown in  FIG. 2 . In use, the downhole valve body  98  is attached by an external thread connection  116  to a downhole pump  12  ( FIG. 1 ) and attached by threading  118  to the downhole pump connector  86  ( FIG. 5 ). The downhole pump comprises a pump pressure chamber  18  ( FIG. 1 ) and could be, for example, the downhole pump shown in the embodiment of  FIG. 2 . Power fluid is supplied to the pump pressure chamber  18  ( FIG. 1 ) when sufficient pressure to open a gas lift valve  100  is applied. The gas lift valve  100  is pressure activated to facilitate supplying power fluid to the pump pressure chamber. From the gas lift valve  100  the pressure fluid flows through a fluid conduit  120  into a pressure regulating check valve  104  and through a power fluid outlet  106  to the pump pressure chamber  18  ( FIG. 1 ). Between the gas lift valve  100  and the pressure regulating check valve  104  is a passage to the actuator of the pump chamber pressure release valve  28  from the fluid conduit  120 . The power fluid being supplied to the pump pressure chamber  18  ( FIG. 1 ) closes the pump chamber release valve and therefore the connection between the pump pressure chamber  18  and the downhole bleed port  27 . Once the pump pressure chamber  18  ( FIG. 1 ) is pressurized to full operating pressure the liquid in the pump pressure chamber  18  ( FIG. 1 ) is expelled into a liquid inlet  108  through a liquid conduit  122  and out a valve body liquid port  102 . The liquid inlet  108  includes a liquid exit tube  26  and an exit check valve  19  ( FIG. 1 ). On a separate port adjacent to the liquid inlet  108  and the power fluid regulating check valve connection  104  is a pump chamber pressure depressurization port  110 . Once this part of the cycle is complete the pressure that activates the gas lift valve  100  is reduced and the gas lift valve  100  closes. With the gas lift valve  100  closed the pump chamber pressure release valve  28  opens to make a connection between the pump pressure chamber  18  ( FIG. 1 ) and the downhole bleed port  27  allowing the pressure in the pump pressure chamber to be bled off. The pump pressure chamber  18  ( FIG. 1 ) is attached by external thread connection  116  to the downhole valve body  98 . After bleeding, liquid from the well bore can enter the pump pressure chamber  18  ( FIG. 1 ) for the next pumping cycle. 
     FIGS. 7A ,  7 B,  7 C and  7 D show cross section views of the embodiment of  FIG. 6  along the lines A, B, C and D, respectively.  FIG. 7A  shows a joint in the fluid conduit  120  that allows the fluid conduit  120  below the joint to lie more to the radial exterior of the downhole valve body below the line A than the fluid conduit does above the line A. In other embodiments such a joint may not be necessary. 
     FIG. 7B  shows a cross section of the embodiment of  FIG. 6  along the line B. The cross section indicates a horizontal connecting passage  128  to be used in an embodiment where liquid conduit  122  could not be drilled straight through the downhole valve body  98  ( FIG. 6 ). A threaded plug  124  separates the liquid conduit  122  from the exterior of the downhole valve body  98  ( FIG. 6 ). In other embodiments horizontal connecting passage  128  may not be necessary. 
     FIG. 7C  shows a cross section of the embodiment of  FIG. 6  along the line C. The cross section indicates a horizontal connecting passage  130  to be used in an embodiment where fluid conduit  120  could not be drilled straight through the downhole valve body  98  ( FIG. 6 ). A threaded plug  126  separates the fluid conduit  120  from the exterior of the downhole valve body ( FIG. 6 ). In other embodiments horizontal connecting passage  130  may not be necessary. 
     FIG. 7D  shows a cross section of the embodiment of  FIG. 6  along the line D. The cross section shows the pump chamber downhole bleed valve  28 , the fluid conduit  120  and then liquid conduit  122 . 
   In an embodiment, once it has been determine that the artificial lift system  60  needs to be pulled, a pressure unit (not shown) is brought in to shear the downhole release mechanism  76  of the artificial lift system. The wing valve  38 C is closed, the pressure unit is connected to the liquid conduit  23  via the wing valve  38 C and the connections are pressure tested. 
   The pressure from the power conduit  8  is bled to 0 psig. The wing valve  38 C is opened and the liquid conduit  23  is pressured up to the desired pressure to shear the breakable fastenings  66  of the downhole release mechanism  76 . The power conduit  8  is pressured up to ensure release has been effective. Then the wing valve  38 C is closed and the pressure unit is rigged out. 
   In an embodiment, if the pressure unit fails to break the breakable fastenings of the downhole release mechanism  76  the external fish neck  80  may be latched on to using wireline tools and the release mechanism sheared and pulled from the wellbore. Prior to the wireline tools latching on to the external fish neck  80  the power fluid conduit  8  must first be cut immediately above the external fish neck  80  and pulled from the wellbore. Wireline can be attached to the downhole release mechanism  76  at the external fish neck  80 , and hammer tools can break the breakable fastenings of the downhole release mechanism  76 . Then the downhole release mechanism  76  may be pulled from the well. 
   In an embodiment, the artificial lift system  60  may be left for a period of time, for example  24  hours, to allow the liquid in the liquid conduit  23  to drain back into the bottom of the wellbore  17  equalizing pressure above and below the artificial lift system  60 . However, there is also the potential to swab liquid from the well in the case that draining fluid back is determined to be an undesirable activity. Other methods of equalizing pressure above and below the artificial lift system  60  may also be used. 
   Gas well pump removal equipment, such as a slickline unit  34  and a crane unit  36  are rigged in to pull the power conduit  8  and the artificial lift system  60  from the wellbore. In an embodiment the slickline unit  34  may rigged in approximately 50 ft from wellhead  38  and crane unit  36  next to wellhead. Other placements of the slickline unit  34  and crane unit  36  are possible. 
   Sections of lubricator  46  are laid out on ground stands. The sections of lubricator  46  are connected together with sufficient length to enclose the complete artificial lift system assembly. The service BOP  44  is installed to bottom of the lubricator sections  46 . 
   Pressure is bled off the power conduit  8 , the surplus power conduit  8  is uncoiled and the valve (not shown) connected to the surface end of power conduit  8  is removed. The production pack-off is removed from the top of production BOP  40  and the adaptor nipple  42  is installed in the top of the production BOP  40 . 
   The end of the surplus power conduit  8  is thread through the bottom of service BOP  44  to the top of the lubricator sections  46 . The end of the surplus power conduit  8  is thread through the lubricator pack-off  48  combined with the top block assembly  50 . The pack-off/top bock assembly  50  is connected to the top of the lubricator sections  46 . The top block support cable  56  is installed between the top block assembly  50  and the crane hoisting cable hook  92 . 
   The top of the lubricator assembly  46  is lifted until the lubricator assembly  46  is hanging vertically above the well head. The surplus power conduit is pulled through the lubricator assembly  46  so that the surplus power conduit can be connected to the slickline unit  34 . The bottom block  52  and the tie down cable  54  are installed. The power conduit  8  is threaded through the bottom block  52 . 
   The end of the power conduit  8  is connected to the slickline unit  34 . The slack from the power conduit  8  is pulled onto the slickline unit&#39;s draw works and the lubricator assembly  46  is lowered onto the wellhead connection and the connection is made. The lubricator assembly  46  is pressure tested to appropriate pressure. 
   The production BOP  40  is opened and the power conduit and the downhole release mechanism  76  are pulled from well. 
   Once the power conduit and the downhole release mechanism  76  are pulled from the well, the top master valve  38 A is closed and the lubricator assembly  46  is laid down. The equipment is then reconfigured to run in a conventional slickline configuration which replaces the power conduit  8  with conventional slickline (not shown) and pulling string (not shown). In an embodiment the pulling string (not shown) comprises a rope socket, sinker bars, mechanical jars, hydraulic jars and a pulling tool. 
   Then, the equipment is rigged in and run in hole. While running in the hole, the liquid level should be determined to ensure the pressure above and below the artificial lift system  60  have equalized. A secondary equalizing mechanism, such as the backup equalizing port  74 , may be activated at this time, if necessary. A pulling tool (not shown) is latched onto the internal fish neck  78  and the artificial lift system  60  is pulled from the hole. 
   The artificial lift system  60  is pulled into the lubricator assembly  46 . The top master valve  38 A is closed. The pressure in the lubricator assembly  46  is bled to 0 psig. The service BOP  44  is disconnected from the adaptor nipple  42  and a cap is installed on the bottom of the service BOP  44 . The lubricator assembly  46  is laid down with artificial lift system  60  inside. The adaptor nipple  42  and production BOP  40  are removed from the top of the wellhead. The original wellhead cap (not shown) is re-installed. 
   The artificial lift system  60  is removed by pulling out the bottom of the lubricator assembly  46  and the artificial lift system  60  is disconnected from the pulling tool. 
   After the artificial lift system  60  is successfully removed, the slickline equipment, slickline unit  34  and crane unit  36  may be rigged out. 
   In an embodiment the artificial lift system may be developed to be operable with existing technology, services and components. In an embodiment artificial lift system may be designed to fit within existing wellbore configurations with only minor modification. In an embodiment the artificial lift system may be designed to not gas lock. In an embodiment the artificial lift system may allow for easy installation and servicing. In an embodiment the artificial lift sytem may be designed to reduce energy consumption. In an embodiment the artificial lift system may be designed for simplicity and trouble free operation. In an embodiment the artificial lift system may be designed as a cost effective pumping alternative. 
   Immaterial modifications may be made to the embodiments described here without departing from what is covered by the claims.