Patent Publication Number: US-7896079-B2

Title: System and method for injection into a well zone

Description:
BACKGROUND 
     Water flood projects are a common approach to enhance oil recovery. Water typically is obtained from an aquifer or from the sea. The water is transported to an injection well site by surface facilities including pumps, filters, water treatment equipment and flow lines. At the injection well site, the water is injected into the desired formation that is to be water flooded. 
     In some environments, the reservoir to be treated by water flooding is positioned below a suitable source of water in the form of a subterranean aquifer. Several techniques have been employed to “dump flood” water from the upper aquifer or/well zone into a lower interval or well zone at a location designed to enhance oil recovery from an oil reservoir. Various techniques have been used to dump flood water from one well zone into another well zone. For example, electric submersible pumping systems have been inverted and installed below the upper zone interval. Water from the aquifer is drawn into the pump intake of the electric submersible pumping system and discharged downwardly into tubing strung into a lower zone packer, thus injecting water into the desired, lower interval. Locating the inverted electric submersible pumping system below the upper interval can pose additional risk from solids production settling onto the pumping system, which can hinder retrieval of the pumping system. 
     Attempts have been made to use a variety of other techniques and equipment for dump flooding water into a lower well zone. For example, systems have been designed to draw fluid to a surface location and to pump fluid back downhole to the desired well zone. Additionally, rod pumps have been employed, and electric submersible pumping systems have been proposed for combination with relatively complex Y-blocks for redirecting flow to the lower well zone. However, each of these approaches suffers from various drawbacks, including lower efficiency, increased space requirements, reduced injection rates, added complexity, and other drawbacks. 
     Other proposals have been made to utilize the natural reservoir pressure for dump flooding a lower well zone. If, for example, the natural pressure in the aquifer is higher than the pressure of the injection zone, the higher pressure can be used to drive water downwardly into the desired, injection zone. However, natural dump flooded wells can be difficult to control. In some applications, restrictors or chokes are installed by intervention or as part of the completion, but such approaches rely heavily on the specific environmental conditions and also increase the difficulty of controlling the injection of water to enhance oil recovery. 
     SUMMARY 
     In general, the present invention provides a system and method for improving a water flood, e.g. dump flood, operation. A standard or non-inverted electric submersible pumping system is deployed in a wellbore to draw water from a water source zone along the wellbore. A shroud and a crossover port are employed to redirect a flow of the water downwardly along an isolated flow path. The controlled, downward flow of water is directed along the wellbore until the water is injected into a desired, injection zone to facilitate, for example, oil recovery. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Certain embodiments of the invention will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements, and: 
         FIG. 1  is a schematic front elevation view of a system for injecting fluid into a well zone, according to an embodiment of the present invention; 
         FIG. 2  is an illustration of a detailed example of the injection system illustrated in  FIG. 1 , according to an embodiment of the present invention; 
         FIG. 3  is a cross-sectional view of a crossover port that can be used with the system illustrated in  FIG. 2 , according to an embodiment of the present invention; and 
         FIG. 4  is a schematic illustration of another example of the injection system illustrated in  FIG. 1 , according to an alternate embodiment of the present invention. 
     
    
    
     DETAILED DESCRIPTION 
     In the following description, numerous details are set forth to provide an understanding of the present invention. However, it will be understood by those of ordinary skill in the art that the present invention may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible. 
     The present invention generally relates to a system and method for injecting a fluid, such as water, into a subterranean well zone. The injection technique can be used to enhance oil recovery from a given reservoir. Generally, the system utilizes a standard or non-inverted electric submersible pumping system which is deployed in a wellbore. The submersible pumping system is positioned to draw fluid from one well zone and to inject that fluid into another well zone. In one injection application, the submersible pumping system draws water from a water source zone and pumps the water to an injection zone. For example, in an oil recovery operation, the injection zone is selected to facilitate recovery of oil from an oil containing reservoir. In some applications, the injection zone lies directly below the oil containing zone or reservoir. 
     The injection system and methodology reduces the surface facilities, pumps, pipelines, and other equipment required in conventional oil recovery operations. Additionally, the system is less subjectable to the effects of space and environmental restrictions while reducing capital expenditure requirements. Furthermore, the injection system enables high injection rates for a variety of dump flood applications. The arrangement of equipment also facilitates easy retrieval of the non-inverted electric submersible pumping system while enabling zone isolation when retrieving the pumping system. 
     In some applications, the system and methodology incorporate monitoring devices at selected downhole locations, e.g. across the water source zone and the injection zone. The monitoring enables, for example, identification and optimization of well efficiency and sweep. A variety of chemicals also can be combined with the water pumped from the water source zone to the injection zone, and this injection of chemicals enables stimulation procedures or water treatment injections during operation of the electric submersible pumping system. Additionally, the injection system can be formed as a concentric design which facilitates running and retrieval operations. Keeping the electric submersible pumping system maintained in a standard (non-inverted) operating configuration is consistent with standard pump installations and therefore the associated reliability and installation experience are well practiced. 
     Referring generally to  FIG. 1 , one embodiment of a system  20  for injecting water into a desired well zone is illustrated. In this embodiment, a completion system  22  is deployed in a wellbore  24  and comprises a non-inverted electric submersible pumping system  26 . The electric submersible pumping system  26  is non-inverted in the sense that it is arranged in a standard orientation within wellbore  24 . For example, the pumping system  26  comprises a submersible pump  28  arranged above a pump intake  30 . The submersible pump  28  also is positioned above a submersible motor  32  which is coupled to a motor protector  34 . Power is provided to submersible motor  32  via an appropriate power cable  36  routed downhole. 
     The non-inverted electric submersible pumping system  26  is deployed into wellbore  24  on a suitable conveyance  38 . Conveyance  38  may comprise a cable-type conveyance, production tubing, coiled tubing, or other suitable conveyance. In many applications, the submersible pumping system  26  is conveyed downhole on production tubing or coiled tubing. Conveyance  38  is used to move submersible pumping system  26  to a desired location in wellbore  24 . In the example illustrated, wellbore  24  is a generally vertical wellbore that extends downward into a subterranean formation  40  from a wellhead  42  positioned at a surface location  44 . However, wellbore  24  can be a deviated wellbore or have deviated sections. Additionally, submersible pumping system  26  can be arranged to deliver water into a lateral wellbore or into a variety of well zones in different locations or orientations than those illustrated. 
     Completion system  22  and non-inverted electric submersible pumping system  26  are arranged to draw fluid, e.g. water, from a source zone  46 , and to route the water to an injection zone  48 . In the embodiment illustrated, the injection zone  48  is located below the water source zone  46 . In other applications, however, water could be drawn from water source zone  46  and injected into an injection zone located above water source zone  46 . Additionally, the water can be injected into a variety of zones at various locations relative to, for example, an oil reservoir zone. In the example illustrated, injection zone  48  is located directly beneath an oil reservoir zone  50 . 
     The various well zones can be isolated from each other along wellbore  24  by isolation devices, such as packers  52 , positioned at various locations along the wellbore. By way of example, packers  52  can be expanded against a surrounding well casing  54  having perforations  56  located at the desired source zone and injection zone. In the embodiment illustrated, a packer  52  is used to isolate water source zone  46  from injection zone  48 , and another packer is located between water source zone  46  and submersible pumping system  26 . In at least some applications, wellbore  24  also can be isolated above the submersible pumping system  26  by a packer, such as the uppermost packer  52  illustrated in  FIG. 1 . 
     During operation of non-inverted electric submersible pumping system  26 , fluid is drawn from source zone  46  to pump intake  30  of submersible pumping system  26 . For example, water can be drawn upwardly along a first isolated fluid flow path, as represented by arrows  58 . As the water flows into pump intake  30 , submersible pump  28  pumps the water and discharges the water into a second isolated fluid flow path, as represented by arrows  60 . The second isolated fluid flow path routes the discharged water downwardly past packers  52  to injection zone  48 , where the water is injected into the injection zone. 
     The electric submersible pumping system  26  is used to generate sufficient energy to inject the required amount of water into the injection zone. As described in greater detail below, the system  20  allows for downhole monitoring and control over each of the well zones. The system  20  also provides for simultaneous injection of acid or other treatment chemicals, isolation of individual zones during pump change out, sand control for one or both of the water source and injection zones, and use in not only vertical wells but also multi-lateral well and deviated well applications, including horizontal well applications. In the embodiment illustrated in  FIG. 1 , system  20  is deployed in a cased wellbore, but the system also can be utilized in open hole wells. 
     One example of an injection system  20  that can be used in many of these applications is illustrated in  FIG. 2 . In this embodiment, electric submersible pumping system  26  is oriented in the standard or non-inverted configuration, and a shroud  62  is positioned around the electric submersible pumping system  26 . The shroud  62  defines, at least in part, the isolated fluid flow paths  58  and  60 . For example, fluid from source zone  46  flows into intake  30  of submersible pumping system  26  along an interior of shroud  62  between submersible pumping system  26  and shroud  62 . The fluid is discharged by submersible pumping system  26  through, for example, a ported sub  64  positioned above the shroud  62  so that the discharged fluid flows along fluid flow path  60  in a downward direction along the exterior of shroud  62 . In the example illustrated, a portion of fluid flow path  60  is disposed between shroud  62  and the surrounding wellbore wall, e.g. surrounding well casing. 
     In this example, the source zone  46  is a water source zone which can be located at, for example, an upper interval or a bottom interval of the well. In the specific example illustrated, the water source zone  46  is an upper zone/interval and provides the source water for injection into injection zone  48  located below the water source zone  46 . The water source zone may be chosen based on a variety of factors, including proximity to the injection zone  48 , water quality, and reservoir quality. The source zone can be open or conventionally cased and perforated in a vertical, deviated or horizontal well. In some applications, the source zone can be accessed via a lateral leg extending from a main wellbore. As illustrated, the injection zone  48  can be located below a hydrocarbon bearing zone/reservoir which requires, for example, additional pressure support to compensate for field hydrocarbon production. The injection zone also can be open or conventionally cased and perforated in a vertical, deviated or horizontal well; or the zone can be accessed via a lateral leg from a main wellbore. 
     The packers  52  are used to isolate various zones along wellbore  24  and may include seal bore packers located between the aquifer or source zone  46  and the injection zone  48  as well as between the upper zone, e.g. the source zone  46 , and the shrouded submersible pumping system  26 . In many applications, the two seal bore packers are run and set separately as part of a sandface completion  65 , followed by installation of the electric submersible pumping system  26 . The packers  52  also may comprise an optional production packer placed above the ported discharge sub  64 . Use of a production packer above the electric submersible pumping system  26  and ported discharge sub  64  prevents annular pressure from reaching the surface during operation of the submersible pumping system. 
     As illustrated, system  20  also may utilize sand control mechanisms  66  positioned in wellbore  24  at water source zone  46  and/or injection zone  48 . By way of example, the sand control mechanisms  66  may comprise sand exclusion screens or gravel packs. In many applications, a sand control mechanism  66  is used at the water source zone because the formation can be relatively loose, resulting in the production of sand. Sand can be detrimental by reducing the run life of the electric submersible pumping system and by increasing the difficulty of performing electric submersible pumping system work-over operations. 
     System  20  also may incorporate a flow isolation valve  68  positioned at the lower zone, e.g. injection zone  48 . By way of example, isolation valve  68  may be a mechanically operated isolation valve run to the lower zone to isolate the lower zone during pulling and re-running of the electric submersible pumping system assembly. The isolation valve  68  protects the lower well zone from damaging kill fluids. Isolation valve  68  may be operated by a shifting tool  70  located at the bottom of an electric submersible pumping system string  72 . The shifting tool  70  opens isolation valve  68  when the electric submersible pumping system string  72  is run in hole, and closes isolation valve  68  when the string  72  is pulled out of hole. 
     Additionally, a sliding sleeve  74  can be used to provide protection for well zone  46  during run in and pull out operations. In the embodiment illustrated, sliding sleeve  74  is a ported sliding sleeve that selectively enables flow from source zone  46  to electric submersible pumping system  26  during an injection operation. A variety of sliding sleeves  74  can be used to selectively open or close access to the upper well zone. By way of example, sliding sleeve  74  is a mechanical sleeve operated by a shifting tool placed, for example, on the bottom of a crossover port  76 . The sliding sleeve  74  is opened when electric submersible pumping system string  72  is run in hole and closed when string  72  is pulled out of hole. 
     The crossover port  76  directs the flow of fluid that is drawn from source zone  46  and subsequently delivered to injection zone  48 . For example, crossover port  76  receives fluid from source zone  46  and directs the flow of fluid to the interior of shroud  62  between shroud  62  and electric submersible pumping system  26 . The crossover port  76  also receives the fluid that flows downwardly along an exterior of shroud  62  after being discharged through ported discharge sub  64 . The crossover port  76  causes the downwardly flowing fluid to “cross-over” from the annulus region into an isolation tubing  78  which transports the flowing fluid down to the injection zone  48 . The isolation tubing  78  is designed to seal with the lower packer  52 , and a plug  79  is used to block any upward flow through the top of isolation tubing  78 . In this embodiment, it also should be noted that fluid flowing upwardly from water source zone  46  flows into ported sliding sleeve  74  and up through an annulus created along an exterior of the isolation tubing  78 . 
     Before, during and/or after the injection operation, a variety of sensors can be used to monitor well conditions and operational parameters. For example, a plurality of sensors  80  can be deployed along wellbore  24 . In some embodiments, sensors  80  can be deployed along source zone  46  and/or along injection zone  48 , as illustrated in  FIG. 2 . The sensors  80  may be formed as a sensor array to detect the desired well conditions and parameters. For example, sensors  80  may comprise pressure sensors, temperature sensors, pH sensors, flow sensors and other sensors related to the injection operation. Data from sensors  80  is used to evaluate and control various aspects of the injection operation. 
     In one embodiment, sensors  80  are connected to an inductive flux coupler  82  which provides power and communication signals between the upper electric submersible pumping system completion  22 , comprising electric submersible pumping string  72 , and the lower sandface completion  65 . This enables sensors  80  to power up and transmit signals to a surface location via a permanent downhole cable  84  and a downhole electronic interface comprising the inductive coupler  82 . The permanent downhole cable  84  or other suitable control line can be run from the surface along with the electric submersible pumping system  26 . 
     In the embodiment illustrated in  FIG. 2 , chemicals, e.g. acid or other treatment chemicals, can be injected into the flow of fluid from source zone  46  to injection zone  48  during operation of submersible pumping system  26 . The chemicals may be injected through a nipple profile  86  and into the flow of fluid discharged from ported discharge sub  64 . Injection of chemicals through nipple profile  86  and into the discharge flow of fluid avoids introducing the chemicals into the interior of electric submersible pumping system  26 . The chemicals are then carried by the flow of fluid down through isolation tubing  78  and injected into injection zone  48 . The nipple profile  86  also may comprise a standing valve or check valve  88  that ensures the flow of chemicals is in a downward direction. Check valve  88  can further be arranged to enable tubing pressure testing. The chemicals can be run downhole through the conveyance  38  or through dedicated chemical injection lines and may comprise water treatment chemicals, corrosion treatment chemicals, stimulation chemicals, enhanced oil recovery chemicals and other suitable chemicals. 
     Referring generally to  FIG. 3 , one embodiment of crossover port  76  is illustrated. In this embodiment, crossover port  76  is constructed as an assembly including isolation tubing  78 . Isolation tubing  78  extends downwardly from a crossover port body  90  having at least one crossover flow port  92  that extends from the surrounding annulus to an internal flow passage  94 . Internal flow passage  94  is in fluid communication with isolation tubing  78  and is blocked on top by plug  79 . The crossover port body  90  also comprises one or more annular flow ports  96  extending from the bottom to the top of the crossover port body  90 . Annular flow ports  96  are part of fluid flow path  58  and extend through the crossover port body to accommodate fluid flow to electric submersible pumping system  26 . An outer housing  98  extends downwardly from crossover port body  90  and surrounds at least a portion of isolation tubing  78  to create an annular flow area  100 . The annular flow area  100  also forms a portion of fluid flow path  58  for conducting fluid from source zone  46  up to annular flow ports  96 . Outer housing  98  also may comprise a seal assembly  102  positioned to form a sealing engagement with the lower packer as illustrated in  FIG. 2 . 
     Depending on the specific arrangement of components and the environment in which system  20  is utilized, the system can be deployed according to a variety of procedures. In one example, deployment and use of injection system  20  comprises initially drilling wellbore  24 , deploying well casing  54 , and perforating the well casing to form perforations  56 . The sandface completion  65  is then installed in a single trip downhole or, alternatively, in two separate stages. The sandface completion  65  comprises the two lower packers  52  which may be hydraulically set packers or swell packers. The sensors  80  also can be formed as a suitable array or bridle and deployed with the sandface completion  65 . In at least some applications, a gravel pack is then formed at source zone  46  and/or injection zone  48 . 
     Once the gravel pack or gravel packs are placed and the gravel pack proppant is circulated out of hole, a service tool is used to close flow isolation valve  68 . The service tool also can be adapted to close the ported sliding sleeve  74  so that both formation intervals, i.e. injection zone  48  and source zone  46 , are isolated. 
     The completion  22 , with electric submersible pumping system  26  and shroud  62 , is then run downhole for engagement with the sandface assembly  65 . The isolation valve shifting tool  70  is attached at the lower end of the string. For example, the shifting tool  70  can be attached to the bottom of isolation tubing  78 . In some applications, a guide shoe is attached to the bottom of the string to ensure ease of installation into the lower packer  52 . Once inserted, seal assembly  102  seals against an inside bore of the lower packer  52 . At least a portion of inductive coupler  82  also can be deployed with the electric submersible pumping system string. Depending on local requirements and regulations, the upper packer may comprise a production packer to isolate the casing annulus from pressure. If a production packer is used, it may be a cup-style or hydraulic-set, pull to release packer. (If a hydraulic-set packer is used, a nipple profile can be deployed below the packer to enable setting of the packer by pressurizing the tubing.) Also, a splice can be positioned in the production packer so as to run control line  84  through the production packer. 
     As described, a variety of components and arrangements of components can be used in system  20 . Additionally, the shrouded electric submersible pumping system  26  can be deployed downhole by a variety of conveyance methods. One type of conveyance that facilitates the running and retrieval of electric submersible pumping system  26  and its associated completion components is coiled tubing  104 , as illustrated in  FIG. 4 . In this embodiment, both power cable  36  and control line/cable  84  are run with the coiled tubing  104 . For example, the power cable  36  and/or control line  84  can be deployed inside coiled tubing  104  or within a wall of the coiled tubing. A coiled tubing/electric submersible pumping system lower connector  106  is used to connect the coiled tubing with the electric submersible pumping system completion  22 . In some applications, the connector  106  can be designed with a hydraulic release. 
     In addition to optional conveyance methods, system  20  can be deployed in a variety of optional configurations to optimize an injection operation for a given well environment. For example, system  20  can be used with multi-lateral well types in which the upper interval or well zone  46  comprises a junction to a lateral leg that extends into the aquifer. In this embodiment, a lower leg of the multi-lateral well could be utilized as the main bore. In some environments, the water containing aquifer may be at a well zone lower than the injection zone. However, crossover port  76  can be adapted to allow water to be produced from the aquifer, up the isolation tubing  78 , and directly into the bottom of shroud  62  (plug  79  is removed). The fluid discharged from submersible pumping system  26  is routed down both the annulus surrounding the shroud and the annulus surrounding the isolation tubing until being directed into the appropriate injection zone. 
     System  20  also can readily be used with passive flow control devices in the sandface completion  65  or with screen mounted active flow control devices. Additionally, the system  20  is compatible with compartmentalized horizontal wellbores in which swell packers are used in conjunction with screens and passive or active flow control devices that distribute injected fluid along a desired lateral length of the wellbore. These are just a few examples of how system  20  can be adapted for a variety of wells and a variety of environmental conditions. 
     Accordingly, although only a few embodiments of the present invention have been described in detail above, those of ordinary skill in the art will readily appreciate that many modifications are possible without materially departing from the teachings of this invention. Such modifications are intended to be included within the scope of this invention as defined in the claims.