Patent Application
20170356272
Hydrocarbon fluids, e.g. oil and natural gas, are obtained from a subterranean geologic formation, referred to as a reservoir, by drilling a well that penetrates the hydrocarbon-bearing formation. Once a wellbore is drilled, various forms of well completion components may be installed to control and enhance the efficiency of producing fluids from the reservoir. In some applications, an injector well is drilled and used for injection of fluids to facilitate production from a corresponding production well. An injection valve may be deployed with a completion string downhole in the injection well to enable control over the flow of injection fluid.
In general, a system and methodology are provided for controlling operation of a subsurface injection valve in a variety of applications. According to an embodiment, the injection valve comprises a flapper which may be selectively shifted to and held in an open position. Depending on the operational configuration of the injection valve, the flapper may be shifted to the open position via fluid flow along a primary flow passage. However, the injection valve also may be shifted to the open position via a separate actuator controllable via pressure applied independently of fluid flow along the primary flow passage.
Certain embodiments of the invention will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements, and:
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 disclosure herein generally relates to a system and methodology for controlling fluid flow, e.g. fluid flow during an injection operation. For example, an injection valve may be positioned in a well string deployed in a wellbore to control an injection fluid flow during a subsurface injection application. According to an embodiment, the injection valve comprises a flapper which is pivotably mounted in a valve housing to allow down flow of fluid and to automatically block up flow of fluid along the interior of the well string, e.g. along a primary flow passage of the well string. However, the flapper may be selectively shifted to and held in an open position to facilitate a variety of operations which utilize the interior of the well string.
The selective shifting and holding of the flapper in the open flow position may be accomplished via fluid flow along the interior of the well string and through the injection valve. For example, the flapper may be shifted by a flow tube having a restrictor such that sufficient fluid flow along the interior of the well string and through the injection valve causes the flow tube to shift into engagement with the flapper and to hold the flapper in the open flow position. However, the injection valve also may be shifted to the open position via a separate actuator, e.g. piston actuator, controllable via pressure applied independently of fluid flow through the injection valve.
In a specific embodiment, the injection valve is a subsurface injection valve which is in a normally closed configuration. In some applications, the subsurface injection valve is deployed along a well string and retrievable to the surface along the interior of the well string. In this and other embodiments, the injection valve combines an ability to shift and hold open the valve via a flow-induced pressure drop across a flow restrictor and an ability to open the valve via adjustment of a differential pressure, e.g. a differential between the primary flow passage and a tubing casing annulus, acting on a separate actuator. The flow restrictor may comprise an orifice, and the orifice may be a fixed or variable orifice disposed along, for example, a flow tube which interacts with a flapper of the injection valve.
By using a flow restrictor, e.g. orifice, along a movable member, the injection valve may be shifted to an open flow position without controlling or monitoring a tubing pressure or annulus pressure. The flow restrictor, e.g. orifice, may be sized according to a desired injection flow rate and the flow tube may be sized to cover and protect the flapper when the flapper is shifted to the open flow position. When the injection flow is stopped, the flow tube is automatically moved back to its original position and the flapper automatically closes.
In some applications, opening of the injection valve without flow therethrough may be useful. For example, some applications may employ a secondary valve downhole of the injection valve, and the secondary valve may be operated by pressure pulses or other pressure applied through the well string. Thus, it can be useful to open the injection valve for passage of the pressure signal to enable operation of the secondary valve when there is no fluid flowing through the well string. In other words, the separate piston actuator enables selective opening of the flapper without the sufficient fluid flow through the flow restrictor.
By way of example, the piston actuator may comprise a piston exposed to internal pressure within the well string or to annulus pressure along the exterior of the well string. The pressure may be used to shift the piston and to thus open the flapper without the sufficient injection flow passing through the flow restrictor of the injection valve. The pressure supplied to actuate the piston actuator also may be provided by other sources, such as an atmospheric chamber or an internal chamber pre-charged with nitrogen or other suitable gas.
Depending on the application, the injection valve and components of the injection valve may have various configurations. In some applications, for example, the piston may be in the form of a piston rod although the piston may have other forms, such as a concentric piston disposed around the primary flow passage. In some embodiments, the piston is coupled with the flow tube to move the flow tube although the piston can be coupled directly with the flapper. The piston also can be operated incrementally by, for example, supplying sequential pressure pulses to cycle the piston to different operational positions. By way of example, the piston may be coupled with an indexer, e.g. a J-slot indexer. In this latter example, pressure cycles along the annulus (or along another suitable channel) can be used to shift to the indexer and thus move the piston into various positions with respect to the flapper and/or flow tube.
Additionally, the flow restrictor may have various configurations. For example, the flow restrictor may be in the form of a retrievable orifice which can be selectively retrieved to the surface along the interior of the well string. The flow restrictor also may be a fixed size orifice, e.g. a fixed size choke plate, or a variable orifice, e.g. variable Venturi, variable nozzle, flow adjustable orifice, or other type of variable restrictor.
Referring generally to
In the example illustrated, the well string 24 and the downhole equipment 26 also comprise at least one secondary valve 32, e.g. a ball valve, disposed on a downhole side of injection valve 28. In at least some applications, the secondary valve 32 is actuated via pressure applied along the interior flow passage 30 of well string 24. As described herein, the injection valve 28 serves to check unwanted flow up through the well string 24. However, the injection valve 28 also may be selectively shifted and held in an open flow configuration by sufficient down flow of fluid along interior 30 or by actuation of a separate actuator device via, for example, pressure applied independently of fluid flow along interior 30. The ability to shift and hold the injection valve 28 in an open position independently of fluid flow along interior 30 enables use of pressure pulses through injection valve 28 (or other actuation techniques deployed through injection valve 28) to selectively actuate the secondary valve 32.
Additionally, the downhole equipment 26 may comprise at least one packer 34 positioned to enable isolation of a well zone 36 along an annulus 38 disposed between an exterior of well string 24 and a surrounding wellbore wall. In some applications, the well string 24 may be in the form of an injection completion which may be deployed downhole and properly configured prior to isolation of zone 36 and injection of fluid into a surrounding formation 40.
Referring generally to
Under normal operating conditions, fluid flow in the direction of arrow 52 along interior flow passage 30 causes the flapper 42 to open against the bias of spring member 50. (As illustrated, interior flow passage 30 extends through the interior of injection valve 28.) However, the flapper 42 quickly closes, as illustrated in
In various stages of operation, however, it may be desirable to selectively shift and hold the flapper 42 in the open flow position, as illustrated in
The flow tube 54 may be shifted to the engaged position holding flapper 42 open via fluid flow through a flow restrictor 56 coupled with the flow tube 54. As discussed above, the flow restrictor 56 may comprise a fixed orifice, variable orifice, or other type of fixed or variable flow restriction. The flow restrictor 56 is configured to restrict fluid flow along interior passage 30 while allowing some fluid flow through an opening 58. Thus, a sufficient fluid flow along the interior passage 30 of well string 24 and through flow restrictor 56 creates sufficient force to move the flow tube 54 into engagement with flapper 42 until flapper 42 is transitioned to the open flow configuration illustrated in
The flow tube 54 may be biased toward a disengaged position, illustrated in
The injection valve 28 further comprises an independent actuator 64 configured to enable selective actuation of the flapper 42 to the held open configuration independently of fluid flow along interior passage 30. This allows the flapper 42 to be shifted and held in the open flow configuration even without flow along interior passage 30 in a direction of arrow 52. By way of example, the independent actuator 64 may comprise a piston actuator 66 having a piston 68 slidably received in a corresponding piston opening 70 formed within valve housing 44, e.g. within a wall of valve housing 44.
In the example illustrated, piston actuator 66 is coupled with flow tube 54 via a linkage 72. However, the piston actuator 66 also may be coupled directly with flapper 42. When sufficient pressure is applied within piston opening 70 on an opposite side of piston 68 relative to linkage 72, the piston 68 forces the flow tube 54 into the engaged position with respect to flapper 42, thus holding flapper 42 in the open flow configuration illustrated in
Depending on the specifics of a given injection operation, the piston actuator 66 may be configured to expose piston 68 to internal pressure within the well string 24 or to annulus pressure supplied along the annulus 38. The pressure is supplied to selectively create a pressure differential able to shift the piston 68 and to thus open the flapper 42 without the sufficient injection flow passing through the flow restrictor 56. In an example, the pressure differential acting on piston 68 may be created by supplying a higher pressure through the annulus 38 compared to the pressure within interior flow passage 30.
It should be noted the actuator 64 may have various configurations. For example, the actuator 64 may be constructed with a single piston or a plurality of pistons in various shapes, sizes and configurations. In some applications, the piston 68 may be in the form of a piston rod, as illustrated in
Referring generally to
Depending on the application, different types of gases and different configurations of chamber 74 may be utilized for establishing desired pressure differentials able to selectively shift flow tube 54 and flapper 42. In some applications, for example, the coil 76 may be used for containing atmospheric pressure which establishes a negative pressure. In this type of application, the spring member 50 and/or other spring members are positioned on an opposite side of the piston 68 so as to counteract the negative pressure of the atmospheric trap formed in coil 76. In this type of configuration, pressure differentials between the interior flow passage 30 and interior of coil 76 can again be used to selectively shift the flow tube 54 and flapper 42.
To accommodate various applications, the number and arrangement of injection valves 28 may vary from one injection well application to another. The injection valve(s) 28 may be utilized in both lateral and vertical wellbores to achieve the desired control over injection fluid flows into surrounding well zones. The injection valve 28 also may be used with many types of completion strings or other well strings to assist in a variety of production operations and/or other types of operations. Similarly, the configuration of each injection valve 28 and the components selected to provide control over the flapper by fluid flow or by pressure may be adjusted according to parameters of the application and/or environment.
Although 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. Accordingly, such modifications are intended to be included within the scope of this invention as defined in the claims.
