Abstract:
Methods for performing a wellbore maintenance operation on a system of wellbores used for improved oil recovery are disclosed. A plurality of wellbores are drilled and perforated to receive production fluids from a reservoir. The wellbores are fluidly connected to a production well that is drilled to a depth below the perforations of the wellbores. The production fluids drain and collect in the production well for delivery to the surface. A pump can be used for delivering the production fluids from the production well. During repair and maintenance operations, a fluid is injected into the production well for safely removing the pump components. The fluid is counterbalanced by the pressures in the connected wellbores such that the fluid does not rise above the perforations in the connected wellbores.

Description:
CROSS-REFERENCE TO A RELATED APPLICATION 
       [0001]    The present application for patent claims the benefit of U.S. Provisional Application bearing Ser. No. 61/286,520, filed on Dec. 15, 2009, which is incorporated by reference in its entirety. 
     
    
     TECHNICAL FIELD 
       [0002]    This invention relates to oil field production apparatus and techniques, and more particularly, to such apparatus and techniques, including wellbore maintenance operations, for use in the production of low pressure wells. 
       BACKGROUND 
       [0003]    In a typical five-spot producing pattern, four production wells are spaced around a production well that is centrally located. Each well operates independently. Rod pumps can be used to assist in lifting the production fluids, which are typically oil and water, to the surface. Pumps for artificial lift extend the field life by reducing the bottomhole pressure and thereby recovering more oil economically. Typically the bottom of the rod pumping string is placed above the producing interval in order to allow fluid separation and minimize the possibility of the string becoming stuck. Fluid levels should be above the pumping string intake to avoid “pounding the pump” which increases wear and reduces the life of the equipment. This in turn results in an increase of backpressure being placed on the reservoir due to the hydrostatic head. Minimizing this hydrostatic head would increase production rates and extend field life and reserves. 
         [0004]    During fairly routine well maintenance operations, wells are often “killed” in order to safely remove and repair the rod strings. Killing a well involves injecting a high density, typically water based, fluid into the production well to provide sufficient hydrostatic pressure to keep the well from flowing. Oftentimes this fluid is displaced into the reservoir. In low pressure gas wells, rod pumps are used to keep water out of the reservoir as much as possible. If significant concentrations of water get into the reservoir, the pressure in the reservoir may not be high enough to move it back out. This often results in a significant effort to get these wells back producing. Sometimes the wells are never successfully returned to production. 
       SUMMARY 
       [0005]    According to an aspect of the present invention, a method of performing a wellbore maintenance operation is disclosed. The method includes providing a drainage wellbore and a production wellbore. The drainage wellbore is perforated such that the drainage wellbore receives reservoir fluids from a producing zone of a subterranean reservoir. The production wellbore is in fluid communication with the drainage wellbore, such as through a drainage string, so that the reservoir fluids received by the drainage wellbore flow to the production wellbore. Fluid is injected into the production wellbore until the flow of the reservoir fluids from the drainage wellbore to the production wellbore is stopped. Maintenance is then performed on the production wellbore. 
         [0006]    In one or more embodiments, fluid is injected into the production wellbore until the fluid level within the production wellbore is at an elevation above the elevation of the perforations in the drainage wellbore. In one or more embodiments, fluid injection is stopped prior to the fluid reaching the perforations in the drainage wellbore. 
         [0007]    In one or more embodiments, at least two drainage wellbores are provided and fluid is injected into the production wellbore until the fluid level within the production wellbore is at an elevation above the perforations in the two drainage wellbores. In one or more embodiments, fluid injection is stopped prior to the fluid reaching any of the perforations in the two drainage wellbores. 
         [0008]    In one or more embodiments, gas is injected into the drainage wellbore to force the fluid back up through production wellbore and allow the reservoir fluids received by the drainage wellbore to flow to the production wellbore. The reservoir fluids can then be produced from the production wellbore. 
         [0009]    According to another aspect of the present invention, a method of performing a wellbore maintenance operation is disclosed. The method includes providing a system of wellbores including a drainage wellbore, a drainage string, and a production wellbore for producing reservoir fluids. The drainage wellbore includes a perforation such that the drainage wellbore receives reservoir fluids from a producing zone of a subterranean reservoir. The drainage string extends between the drainage wellbore and the production wellbore. Reservoir fluids received by the drainage wellbore flow through the drainage string to the production wellbore for production. A fluid is injected into the production wellbore until the hydrostatic pressure in the production wellbore is sufficient to stop the flow of the reservoir fluids received by the drainage wellbore from flowing to the production wellbore. Maintenance is then performed on the production wellbore. 
         [0010]    In one or more embodiments, fluid is injected into the production wellbore until the fluid level within the production wellbore is at an elevation above the elevation of the perforations in the drainage wellbore. In one or more embodiments, fluid injection is stopped prior to the fluid reaching the perforations in the drainage wellbore. 
         [0011]    In one or more embodiments, at least two drainage wellbores are provided and fluid is injected into the production wellbore until the fluid level within the production wellbore is at an elevation above the perforations in the two drainage wellbores. In one or more embodiments, fluid injection is stopped prior to the fluid reaching any of the perforations in the two drainage wellbores. 
         [0012]    In one or more embodiments, gas is injected into the drainage wellbore to force the fluid back up through production wellbore and allow the reservoir fluids received by the drainage wellbore to flow to the production wellbore. The reservoir fluids can then be produced from the production wellbore. 
         [0013]    According to another aspect of the present invention, a method of performing a wellbore maintenance operation is disclosed. The method includes providing a drainage wellbore and a production wellbore. The drainage wellbore receives reservoir fluids from a producing zone of a subterranean reservoir. The production wellbore is in fluid communication with the drainage wellbore such that the reservoir fluids received by the drainage wellbore flow to the production wellbore. A fluid is injected into the production wellbore until the hydrostatic pressure in the production wellbore is sufficient to stop the flow of the reservoir fluids received by the drainage wellbore from flowing to the production wellbore. Maintenance is then performed on the production wellbore. Gas is then injected into the drainage wellbore to force the fluid back up through production wellbore and allow the reservoir fluids received by the drainage wellbore to flow to the production wellbore. The reservoir fluids are then produced from the production wellbore. 
         [0014]    In one or more embodiments, the drainage wellbore is in fluid communication with the producing zone of the reservoir through a perforation in the drainage wellbore. Fluid is injected into the production wellbore until the fluid level within the production wellbore is at an elevation above the elevation of the perforations in the drainage wellbore. 
         [0015]    In one or more embodiments, the drainage wellbore is in fluid communication with the producing zone of the reservoir through a perforation in the drainage wellbore. Fluid injection is stopped prior to the fluid reaching the perforations in the drainage wellbore. 
         [0016]    In one or more embodiments, at least two drainage wellbores are provided, each drainage wellbore being in fluid communication with the producing zone of the reservoir through a perforation in the drainage wellbore. Fluid is injected into the production wellbore until the fluid level within the production wellbore is at an elevation above the perforations in the two drainage wellbores. 
         [0017]    In one or more embodiments, at least two drainage wellbores are provided, each drainage wellbore being in fluid communication with the producing zone of the reservoir through a perforation in the drainage wellbore. Fluid injection is stopped prior to the fluid reaching any of the perforations in the two drainage wellbores. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0018]      FIG. 1  is a schematic, sectional view of a prior art arrangement of production wells extending into a reservoir having hydrocarbons. 
           [0019]      FIG. 2  is a schematic, sectional view of an arrangement of wells extending into a reservoir having hydrocarbons according to an aspect of the present invention. 
           [0020]      FIG. 3  is a schematic, sectional view of the arrangement of  FIG. 2  for workover operations. 
       
    
    
     DETAILED DESCRIPTION 
       [0021]    Referring to prior art  FIG. 1 , a plurality of production wells  11  are spaced for producing hydrocarbons from a reservoir  13 . Production wells are spaced in a typical five-spot producing pattern, as shown in  FIG. 1 , for production of hydrocarbons from reservoir  13 . Each well  11  operates independently in the five-spot pattern shown in  FIG. 1 . Each well  11  typically comprises a plurality of casing strings inserted into the well after being drilled and then cemented into place. The plurality of casing strings collectively define the outer boundary or outer casing  15  of well  11 . For ease of illustration, the plurality of casing strings of outer casing  15  are represented in  FIG. 1  as a single string of casing. After reaching the desired depth in reservoir  13 , such that well  11  extends to oil sands  19 —a portion of a reservoir having hydrocarbons, the outer casing is perforated. Forming perforations  17  allows fluid communication between oil sands  19  of reservoir  13  and the interior of well  11 . 
         [0022]    Each well  11  typically includes a string of production casing or tubing  21  that is carried within outer casing  15 . Tubing  21  has an opening for receiving production fluids (typically oil, water, and gas) at its lower end. Packer seals  23  are positioned between production tubing  21  and casing  15  to force production fluids from reservoir  13  to flow through production tubing  21 . 
         [0023]    Pump assemblies  25 , which have a rod pumping string positioned within production tubing  21 , are used for communicating production fluids to the surface. For example, pump assemblies  25  can be used when the pressure associated with reservoir  13  is low and produced fluids do not flow to the surface. Pump assemblies  25  help to extend the life of wells  11 . 
         [0024]    Typically the bottom of the rod pumping string of pump assembly  25  is positioned above “the producing interval” in order to allow initial fluid separation between the gas and liquid phases of the production fluids, and to minimize the possibility of the string becoming stuck. It is preferable that the fluid levels of the liquids in the production fluids remain above the pumping string intake to avoid “pounding the pump” which increases wear and reduces the life of the equipment. Maintaining the liquid levels of the production fluids above the intake of pump assembly  25  increases the hydrostatic head within production tubing  21  which in turn results in backpressure being placed on reservoir  13 . Reducing this hydrostatic head can further increase production rates and extend field life associated with reservoir  13 . 
         [0025]    Referring to  FIG. 2 , a plurality of drainage wellbores  27  extend to production depths within reservoir  13 . Drainage wellbores  27  are spaced apart similar to the outer production wells  11  in the five-spot producing pattern of  FIG. 1 . Drainage wellbores  27  have perforations  29  formed in the respective outer casings  31  for receiving production fluids from reservoir  13 . Perforation  29  associated with one drainage wellbore  27  can be at a different reservoir depth from perforation  29  of another drainage wellbore  27  for optimal hydrocarbon production. Each drainage wellbore  27  also includes packer seal  32  positioned within casing  31  above perforation  29 . 
         [0026]    Production well  11 ′ extends into reservoir  13  adjacent drainage wellbores  27 . Production well  11 ′ is drilled and completed with substantially the same components as wells  11  in  FIG. 1 , except that production well  11 ′ extends deeper into reservoir  13  than drainage wellbores  27 . A plurality of drainage strings  33  extend between a lower end portion of production well  11 ′ and drainage wellbores  27  so that production well  11 ′ is in fluid communication with drainage wellbores  27 . Because lower end portion of production well  11 ′ is deeper than drainage wellbores  27 , gravity helps production fluids from drainage wellbores  27  to collect within production well  11 ′ for collection with pump assembly  25 ′. Drainage strings  33  can be formed with directional drilling techniques when first drilling drainage wellbores  27  and production well  11 ′, or with directional drilling between existing wells in an older field. Drainage strings  33  preferably comprise a string of casing or tubing that is installed after drilling. 
         [0027]    As shown in  FIG. 2 , pump assembly  25 ′ is disposed within production well  11 ′. Drainage wellbores  27  do not include pump assemblies  25 ′. This inherently reduces the amount of maintenance associated with the wells of the five-spot pattern shown in  FIG. 2 . Moreover, this also helps to reduce the cost and maintenance associated with pump assemblies  25  ( FIG. 1 ) by only having a single pump assembly  25 ′ ( FIG. 2 ). In  FIG. 2 , production well  11 ′ is positioned in the center of drainage wellbores  27 . However, production well  11 ′ can be any of the positions in the five-spot pattern. Furthermore, drainage wells  27  and production well  11 ′ can be in other production patterns. In the system of  FIG. 2 , packer seals  32  can be cheaper packer seals since there is not a string of production tubing being sealed between outer casing  31 . This also provides for additional cost savings and reduction of maintenance. 
         [0028]    As shown in  FIG. 2 , production well  11 ′ can be without any perforations  17  such that production well  11 ′ is merely used for collecting and delivering production fluids from drainage wellbores  27 . Not having any perforations within production well  11 ′ advantageously allows the rod pumping string of pump assembly  25 ′ to be set below the perforations in all of the other connecting drainage wellbores  27 . This achieves the lowest possible bottom-hole pressure in the connecting wells by having a fluid level below the perforations while still maintaining fluid level over the rod string entry. In such a system, higher production rates can be achieved and additional reserves can be realized. 
         [0029]      FIG. 3  illustrates how the assembly of the present invention is advantageous during workover operations. During workover operations on the well, the pump rod string of pump assembly  25 ′ is often removed. Additionally, pump rod string of pump assembly  25 ′ can be removed for maintenance and repair of pump assembly  25 ′, which is fairly routine. 
         [0030]    As previously described, to perform such operations in conventional well arrangements, such as production wells  11  shown in  FIG. 1 , wells are often “killed” in order to safely pull the rod pumping string of pump assembly. “Killing” production well  11  ( FIG. 1 ), typically involves injecting a high density, typically water-based, fluid into production well  11 . This provides sufficient hydrostatic pressure to keep production well  11  from flowing (i.e., cease flow of production fluids into production well  11  through perforations  17 ). It is common for the injected fluid used for “killing” well  11  to get displaced into reservoir  13 . In low pressure gas wells, such as production wells  11  shown in  FIG. 1  and production well  11 ′ shown in  FIG. 2 , pump assemblies  25 , 25 ′ are used to keep water out of reservoir  13  as much as possible. Reducing backflow of water into reservoir  13  is important because if significant concentrations of water enter into reservoir  13 , the pressure in reservoir  13  may not be high enough to move the water-based injected fluid back out. When the water-based injection fluid does flow into reservoir  13 , this often results in a significant effort to get production well  11  producing again—sometimes production wells  11  are never successfully returned to production. 
         [0031]    According to a method of the present invention, fluidly connected production well  11 ′ and drainage wellbores  27  act as the closed end of a manometer. In order to “kill” production well  11 ′ and drainage wellbores  27 , fluid can be injected into the bore of production well  11 ′. As the fluid level of the injected fluid and the produced fluid collecting in production well  11 ′, drainage wellbores  27 , and drainage strings  33  rises, the fluid compresses the separated gas above it in drainage wellbores  27 . As seen in  FIG. 3 , fluid can be injected into production well  11 ′ until the fluid level within production well  11 ′ is at least above perforations  29  in all of drainage wellbores  27 . The hydrostatic pressure in production well  11 ′ is balanced by the hydrostatic pressure of the fluid in drainage wellbores  27  plus the pressure of the compressed gas phase in drainage wellbores  27 . As a result, the fluid level in drainage wellbores  27  is lower than in production well  11 ′, and the fluid can be kept below perforations  29 . With the fluid (produced fluid and the water-based injected fluid) being below perforations  29 , the risk of the fluids flowing into reservoir  13  is significantly reduced. Therefore, maintenance and repairs can be performed while production well  11 ′ is “killed,” while reducing the difficulties with returning production well  11 ′ to production. 
         [0032]    Moreover, returning production well  11 ′ after maintenance is performed is simplified as gas can be injected into drainage wellbores  27  to push the fluid back up through production wellbore  11 ′. Accordingly, this reduces the likelihood of the “kill” fluid from entering perforations  29  and allows the reservoir fluids received by drainage wellbore  29  to resume flowing to production wellbore  11 ′. Accordingly, the reservoir fluids can then be produced again from the production wellbore. 
         [0033]    While the invention has been shown in only some of its forms, it should be apparent to those skilled in the art that it is not so limited, but susceptible to various changes without departing from the scope of the invention.