BACKGROUND OF THE INVENTION Efficiently producing hydrocarbon fluids from downhole formations is a challenging process involving a multitude of different types of equipment and techniques for recovering the fluids from the selected formation. Normally, when production from a hydrocarbon reservoir is commence, the fluid pressure present in the formation is sufficient to force the liquids to the surface for recovery. After a period of time, however, the natural formation pressure may decline to a point where the pressure is not sufficient to lift the formation fluids to the surface at the desired rate of recovery. In these instances, alternative methods of enhancing the extraction of hydrocarbon fluids from the formation may be employed to augment recovery of formation fluids.

One method of enhancing the recovery of hydrocarbons from a formation is to decrease the hydrostatic head of the column of fluid in the wellbore. Decreasing the hydrostatic head enhances recovery by reducing the amount of pressure required to lift the fluids to the surface. Decreasing the density of the column of fluid extending from the formation to the surface is a technique utilized to reduce the hydrostatic head of the fluid column. For example, mixing a lower density fluid with formation fluids reduces the overall density of the fluid column and consequently decreases the hydrostatic head.

One way to achieve this is by forcing a lift fluid, typically a gas or hydraulic fluid having low density, down the annulus between the production tubing and the casing of the well. The low density fluid is then injected into the production tubing at one or more predetermined locations where it mixes with formation fluids, lowering the density of the fluid column above the formation. The injection of the low density fluid into the production tubing, however, must be carefully controlled to avoid equipment damage while

simultaneously providing for optimal recovery. For example, excessive injection rates can result in pressure surges in the tubing and related equipment. Such pressure surges may produce large and destructive forces within the production equipment.

Control of the injection rate is typically accomplished using an orifice, the size of which is typically determined using a trial and error procedure. The operator attempts to "dial in"the well by regulating the rate of injection of the low density fluids with various size orifice valves until optimum production is reached. In practice, the well operator will typically try several orifice settings, allowing the well to stabilize after each adjustment. Due to the distances and respective volumes involved, the operator may spend a significant amount of time in making the adjustments, stabilizing production after each adjustment and collecting comparative data from the different settings to establish performance trends.

Therefore, a need has arisen for a control system to automate the process of adjusting the flow rate of a low density fluid to optimize production based upon well parameters. A need has also arisen for such a system that reduces the operator time and attention required to"dial in"the well. Additionally, a need has arisen for a precise control system that periodically monitors and adjusts the injection rate of the low density fluid into the production tubing.

SUMMARY OF THE INVENTION The present invention disclosed herein comprises a system and method to automate control over the flow of a lift fluid into a wellbore of a hydrocarbon producing well to enhance recovery of fluids from a formation. The system and method maximize recovery based upon well parameters while minimizing the time and attention of the operator typically required to"dial in"the well. The system and method provide precise control over the flow of the lift fluid into the wellbore by periodically monitoring and adjustment of the rate of injection of the lift fluid.

In the system of the present invention, a flow control device, such as a control valve or choke valve, is disposed within the wellbore. The flow control device is adjustable between various positions to regulate the injection of the lift fluid into the tubing wherein formation fluids are being produced. A sensor monitors the rate of recovery of the formation fluids. The sensor providing signals indicative of the rate of recovery of the formation fluids to a controller. The signals may be transmitted to the controller using an electronics package disposed downhole. The controller receives the signals and adjusts the position of the flow

control device in response to the signals to regulate the rate of injection of the lift fluid. The low density fluids are injected into the tubing to reduce the hydrostatic head of the formation fluids in the tubing and provide artificial lift thereto. The lift fluid may be either a gas or a liquid.

The controller includes a set of preprogrammed instructions for determining the optimum position of the flow control device by incrementally adjusting the position of the flow control device in response to the signals received from the sensor. For example, the controller may incrementally adjust the position of the flow control device to increase the rate of injection of the lift fluid when the sensor indicates that the rate of recovery of the fluids increased in response to a prior increase in the rate of injection of the lift fluid.

Conversely, the controller may incrementally adjust the position of the flow control device to decrease the rate of injection of the lift fluid when the sensor indicates that the rate of recovery of the fluids decreased in response to a prior increase the rate of injection of the lift fluid.

In one embodiment, the flow control device is incorporated into a downhole tool and is pneumatically or hydraulically actuated from a remote location. The controller is positioned at or near the wellhead and includes a computer or programmable controller as well as line pressurization and bleed down actuators for regulating the flow control device.

The controller may also include a sensor to monitor control line pressure. Preferably, the controller will be capable of interfacing with any existing sensors for annulus pressure, tubing pressure, injection rate and flow rate. In the event that such sensors are not present. the controller may be provided with sensors adaptable for installation at the wellhead or on existing line fittings.

The method of the present invention involves disposing an adjustably positionable flow control device within the wellbore, determining the rate of recovery of the fluids with a sensor, generating signals indicative of the rate of recovery of the fluids and adjusting the position of the flow control device in response to the signals to regulate the injection of the lift fluid into the formation fluids, thereby enhancing the recovery of the formation fluids.

BRIEF DESCRIPTION OF THE DRAWINGS For a more complete understanding of the present invention, and the advantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying drawings, wherein like elements are numbered alike and wherein: Figure 1 is a schematic illustration generally showing one configuration of a well utilizing a fluid injection apparatus of the present invention; Figure 2 is a schematic illustration of a fluid injection control valve utilized in the practice of the present invention; Figure 3 is a graphical representation of the relationship between the injection rate of a density compensating fluid and the flow rate of formation fluids from a well; and Figure 4 is a block diagram illustrating various steps utilized in the system of the present invention to control the rate of fluid injection into a well.

DETAILED DESCRIPTION OF THE INVENTION While the making and using of various embodiments of the present invention are discussed in detail below, it should be appreciated that the present invention provides many applicable inventive concepts which can be embodied in a wide variety of specific contexts.

The specific embodiments discussed herein are merely illustrative of specific ways to make and use the invention, and do not limit the scope of the invention.

Referring now to Figure 1, a well installation incorporating the features of the present invention is schematically illustrated and generally designated 10. The well is cased with a normal casing 100. A tubing string 102 extends through the casing 100 for conventional extraction of hydrocarbon fluids. Hydrocarbon fluids are produced into tubing 102 at a point below seal assembly 104 that provides a sealing engagement between tubing 102 and casing 100.

At the well surface, formation fluid flow may be controlled by one or more choke or control valves 108. Under the appropriate conditions, fluid flow from the formation through the tubing 102 may be enhanced through the use of an artificial lift technique such as injection of a lift fluid. To achieve maximum production, however, the optimum injection rate of the lift fluid must be determined.

In the illustrated embodiment, a lift fluid source 105 such as a compressor or pump is provided to supply the low density lift fluid to injection tool 106. The lift fluid travels through annulus 112 and enters tool 106 through inlet ports 130. The injection rate of the

lift fluid is monitored with flow sensor 107. As an alternative to lift fluid source 105. a lift fluid may be provided from a different location in the well or from another well, depending upon the particular location. As will be appreciated by those skilled in the art. the lift fluid may be a gas or a liquid and, as used herein, the term"lift fluid"shall include both gases and liquids utilized to adjust the density of formation fluids during the recovery process irrespective of the physical phase of the lift fluid into the tubing 102. Also. as will be appreciated by those skilled in the art, the system of the present invention is not limited to the use of a particular tool or injection means.

In the illustrated embodiment, injection tool 106 includes a hydraulically actuated control valve or downhole adjustable choke valve 134. Hydraulic pump 103 provides control pressure via control line 114 to the tool 106. The control pressure is regulated by a controller or control unit 101 that provides the desired hydraulic control pressure to tool 106.

In one embodiment, the control unit 101 is a portable unit, remotely positioned from the tool 106. The control unit 101 may be located at or near the wellhead or at a more remote location depending upon the particular application. The control unit 101 includes a computer or an electronic programmable controller and line pressurization actuators, either hydraulic or gas, for the application and bleed-down of pressure to choke valve 134. The control unit 101 may also incorporate instrumentation to monitor the pressure in control line 114 to determine when the pressure in the control line 114 has equalized. Preferably, the control unit 101 is adaptable to interface with existing sensors to determine annulus pressure, tubing pressure, injection rate and flow rate. If these sensors are not incorporated into the well apparatus, the control unit 101 may be provided with instrumentation suitable for installation at the wellhead or on existing line fittings. The system of the present invention may also include a downhole electronics package communicably coupled to one or more sensors for transmitting information to the remotely located control unit 101.

In the illustrated embodiment, the control unit 101 may receive information from a variety of different sensors. The pressure and/or flow rate of the lift fluid are measured with sensor 107 and transmitted to the control unit 101 as schematically represented by dashed line 120. Similarly, the pressure and/or flow rate of recovered formation fluids may be monitored with sensor 110 and relayed to the control unit 101 as indicated with dashed line 121. The tool 106 may be equipped with a sensor and electronics package 135 for monitoring tubing pressure, casing pressure, temperature, valve position and other variables of interest that may be transmitted to the control unit 101 as schematically represented by

dashed line 122. Transmission of data by the electronics package 135 may be accomplished in a variety of ways including, but not limited to, by electromagnetic, acoustical or hardwired telemetry as will be appreciated by those skilled in the art.

Turning now to Figure 2 there is illustrated a schematic cross-sectional view of a flow control system such as a downhole adjustable choke valve 134 disposed with tubing 102 and suitable for use in connection with the system of the present invention. In the illustrated embodiment, lift fluid flows down between tubing 102 and casing 100 through inlet ports 128 and into choke valve 134 as generally indicated by arrows 116. The lift fluid travels through central bore 118 of choke valve 134. In the illustrated embodiment, the production fluids are diverted around choke valve 134 as generally indicated by arrows 126. The lift fluid is injected into the production fluids above choke valve 134 inside of tubing 102. As illustrated, the lift fluid is injected into the tubing 102 at a single location. As will be appreciated by those skilled in the art, the lift fluid may be injected into tubing 102 at multiple locations.

As illustrated in Figure 2 the lift fluid passes through central port 118 as generally indicated by arrows 116. The lift fluid to be injected into tubing 102 enters valve body 162 and passes through orifice plate 164 via orifice 166. The flow of lift fluid through valve body 162 is controlled with poppet 160 which is positioned relative to the orifice plate 164 by actuator 136. As illustrated, in order to adjust the flow of lift fluid through choke valve 134, poppet 160 is advanced or retracted relative to the orifice plate 164, thereby decreasing or increasing the effective opening of orifice 166. As previously noted, choke valve 134 is actuated by a hydraulic actuator 136 operatively connected to choke valve 134. Although choke valve 134 is illustrated as a poppet type valve, other variable position choke valves may be utilized in the practice of the invention.

Now turning to Figure 3, the flow rate of formation fluids in a well as a function of the injection rate of the lift fluid is depicted. As shown, recovery as a function of injection rate reaches a maximum at the intersection of the axes designated y'and z'. Injecting additional lift fluid beyond the maximum rate indicated by the intersection of the designated y'and z'axes actually decreases the productivity of the well.

As best illustrated in Figures 3 and 4 in conjunction, the system and apparatus of the present invention optimize well productivity by adjusting the rate of lift fluid injection. As explained above with reference to Figure 1, controller 101 includes preprogrammed instructions stored on a conventional memory device to generate a signal at step 200 to

initialize or reset the flow rate of the lift fluid in response to an operator command, at predetermined intervals or in response to a change in flow rate. The orifice position of the downhole adjustable choke valve 134 is set at step 210 to a predetermined initial position.

In step 220 the flow rate and pressure are monitored to determine whether the well has stabilized at the particular injection rate. Flow rate and pressure data are then collected for the particular orifice position in step 230 via sensors 107,110. Once the data is obtained for the first orifice position, the orifice is incremented to the next position in step 240. If there are additional orifice positions in step 250, the well is again allowed to stabilize in step 220 and the process of data collection (step 230) and orifice incrementing (step 240) are repeated until all desired orifice positions have been tested. Once all the desired positions of the orifice have been tested, the data collected in step 230 is analyzed to determine the optimal orifice position in step 260. Thereafter. the operator is notified in step 270 that the process is complete and which orifice size is optimal for the well.

As best illustrated in Figure 3, the flow rate of formation fluids from the well is monitored as a function of an incremental change in the rate of injection of the lift fluid. The injection rate of the lift fluid is initially increased in increments 280 based upon preprogrammed instructions resident on control unit 101. The magnitude of incremental increases 280 may be directly proportional to the changes in the flow rate or otherwise determined by control unit 101 and may be varied depending upon the particular application and well conditions. As the rate of injection increases, the flow rate reaches a maximum as shown by the intersection of axis y'and z'. Increasing the rate of injection beyond this point as indicated by incremental increases 290 decreases the flow rate of production fluids.

Before the theoretical maximum flow rate is reached, however, a zone of instability 300 may be entered. As the production nears the zone of instability 300, the magnitude of the incremental increases are reduced to fine tune the system as shown by incremental increases 310. The optimal flow rate is thus not the maximum flow rate depicted in the curve but rather a point close to, yet below, the zone of instability 300. Thus, by stepping through each of the orifice positions as described with reference to Figure 4, information is obtained with regard to the relationship between the injection rate of lift fluid and flow rate of production fluid. This information is thereafter used to select an orifice size that corresponds to the optimal flow rate.

This process may be performed periodically to assure that the optimal flow rate is being maintained over time. The instructions programmed into control unit 101 may also

include commands to adjust or reduce the flow of lift fluid in the event that the flow of formation fluids becomes unstable or in the event of sudden changes in pressure or flow rate.

While this invention has been described with a reference to illustrative embodiments, this description is not intended to be construed in a limiting sense. Various modifications and combinations of the illustrative embodiments as well as other embodiments of the invention, will be apparent to persons skilled in the art upon reference to the description. It is, therefore, intended that the appended claims encompass any such modifications or embodiments.