The invention relates to a control system and in particular, a control system for controlling the production of fluid from a well.

Use of gaslift injection to maximise the production of oil and gas from a well has been used for a number of years and has been used on both land based and offshore wells.

Typically, equipment for such an operation comprises a tubing string which extends into the well and which has a plunger movable within the tubing string between a bottom position and an upper position. Below the bottom position of the plunger, a gas injection valve is located in the tubing so that gas injected into the annulus between the casing and the tubing at the surface can enter the tubing string below the plunger. When sufficient pressure of gas has been injected below the plunger to overcome the weight of production fluid above the plunger, the plunger rises up the tubing pushing the production fluid above the plunger up the tubing and out at the surface through a flowline.

After reaching the upper position, the plunger is allowed to fall back down the tubing to the bottom position and the cycle is repeated.

Attempts have been made to control and optimise the amount of fluid produced. However, these previous attempts have only monitored the number of cycles of the plunger in order to optimise the amount of fluid produced. However, this has proved to be an unreliable method of optimising or controlling the amount of fluid produced by the well.

In accordance with the present invention, a control system for controlling the production of fluid from a well by gaslift injection comprises cycle monitoring means for monitoring the number of cycles performed by a plunger in the well, volume metering means to meter the produced volume of fluid, and a processing device coupled to the cycle monitoring means and the volume metering means to receive output signals from the cycle monitoring means and the volume metering means, the processing device controlling the number of cycles and the amount of gas injected in response to the output signals received in order to control the volume of fluid produced from the well.

In accordance with another aspect of the invention, a method of controlling the production of fluid from a well by gaslift injection comprises monitoring the number of cycles performed by a plunger in the well and metering the volume of produced fluid from the well, analysing these variables and controlling the number of cycles and the amount of gas injected in response to the result obtained from the analysis, to control the volume of fluid produced from the well.

The invention has the advantage of metering the produced volume of fluid from the well, as well as the number of cycles of the plunger, in order to control the volume of fluid produced from the well.by controlling the number of cycles and the amount of gas injected into the well.

Typically, the control system may also include gas injection metering means to meter the amount of gas injected to produce the fluid, and the processing device receives an output signal from the gas injection metering means and also uses this output signal to control the volume of fluid produced.

Typically, the gas is injected via a surface located gas lift control valve and a downhole gas lift injection valve.

Preferably, the control system may also comprise pressure sensing means coupled to the processing device to permit the processing device to monitor the casing and/or tubing pressures in the well. Typically, the pressuring sensing means are analogue devices and the processing device may monitor the rate of change of pressure.

Preferably, the control system also controls a flowline valve to control the amount of fluid produced from the well and typically, the flowline valve is closed by the control system when the plunger reaches its upper position in the tubing. Typically, the processing device may also control the upward velocity of the plunger per cycle, the time of commencement of gaslift injection and/or the well blowdown time. Preferably, the upward velocity of the plunger per cycle is

controlled by varying the injected volume of gas. Typically, this may be accomplished by overriding the downhole gas lift valve by sustaining sufficient pressure in the annulus between the casing and tubing to maintain the downhole gas lift valve in an open position.

Preferably, the flowline valve and the surface located gas lift valve may be opened to intermediate positions to permit the flow through the valves to be varied.

Preferably, the control system may have a number of pre-set boundary conditions which may include one or more of maximum gaslift consumption, maximum gas/oil ratio in the produced fluid, minimum gaslift supply pressure, maximum and minimum allowable casing pressure, maximum flowline pressure and minimum flowline pressure and rate of drawdown of gas lift supply pressure.

Typically, the processing device may include a pre-set safety shutdown procedure which is initiated by the control system if it detects an unacceptable or unsafe condition in the production system.

Preferably, the control system can optimise production from more than one well, and typically, controls production so that no two wells produce simultaneously. This helps reduce the possibility of production facilities becoming overloaded.

Preferably, the processing device can log data from each of the wells simultaneously.

Typically, where the control system controls more than

one well and the wells are not adjacent to each other, the other wells are provided with slave control systems controlled by the control system on one of the wells.

Preferably, the control system also includes communication means to permit the control system to communicate with a base station and/or to communicate with the control systems of other wells.

Typically, the control system controls the volume of fluid produced from the well to optimise the production cycle (i.e. produced volume of fluid verses gas injected) and provides safety shutdown should the system pressure parameters be violated.

An example of a control system for controlling the production of fluid from a well in accordance with the invention will now be described with reference to the accompanying drawings, in which:-

Fig. 1 is a schematic diagram of a production system for use with a control system; Fig. 2 is a schematic diagram showing a control system for use with the production system shown in Fig. 1; and, Fig. 3 is a flow diagram showing the main operational procedure of the control system;

Fig. 1 shows a typical production system 1 for a well which is lined with casing 2. The production system 1, comprises a tubing string 3 located within the casing 2 which extends from a surface located wellhead 4 to a no-go standing valve 5 which is adjacent perforations 6 in the casing 2 of the well. The perforations 6 permit production fluid to flow from the surrounding

geological formations into the casing 2 and enter the tubing 3 via the no-go standing valve 5. Located above the no-go standing valve 5 is a sliding door 7 which is optional and above that is located a production packer 8. The packer 8 prevents production fluid rising to the surface through the annulus between the tubing string 3 and casing 2.

Above the packer 8, a side pocket mandrel 9 is located in the tubing string and the side pocket mandrel 9 has a downhole gaslift valve 10 to permit gas injected into the annulus between the tubing 3 and casing 2 to enter the tubing 3. Above the pocket mandrel 9 is located a lower bumper spring 11 and a stop collar 12 which define the lowest position possible of a plunger 13 which can slide up and down the tubing string 3.

Above the wellhead 4 is located a master valve 14 and a swab valve 15. Above the swab valve 15 is located a receiver/lubricator 24 with a manual plunger catcher 16 and a plunger sensor 33. A side outlet 17 diverts production fluid from the well into a flowline 18 through an elbow adapter 19 and a flowline valve 20. The production fluid passes from the flowline 18 through a check valve 21 and manual valve 22 before entering the main product line 23.

Above the receiver/lubricator 24 is located a bumper sub 26 which defines the uppermost position of the plunger in the production system 1. The receiver/lubricator 24 is connected to the bumper sub 26 by a wireline access union 25.

The gas injection line 27 is coupled to the annulus between the tubing 3 and casing 2 just below the

wellhead 4 and the injection of gas into the annulus is controlled by a gas lift valve 28. Gas to the gas injection line 27 passes from a main reservoir 29 through a manual valve 30, check valve 31 and gas choke 32.

Fig. 2 shows a control system 35 for controlling the production system 1 shown in Fig. 1. The control system 35 comprises a micro-processor unit 36 which receives power from a power source 37 and power supply unit 38. The processor 36 is coupled to a communications unit 39 and to a data logging unit 40. The data logging unit 40 is coupled to a data extract unit 41 which supplies data to a data storage display and design unit 42.

The micro-processor 36 receives inputs on input lines 43 and controls the flowline valve 20, the gaslift valve 28, the plunger catcher (receiver/lubricator) 24 and the downhole gaslift valve 10 via respective output control lines 44, 45, 46, 47.

The inputs 43 to the micro-processor unit 36 take outputs from transducers and sensors on the production system 1 which correspond to tubing head pressure, casing head pressure, flowline pressure, gaslift differential pressure, wellhead sensor, ball valve limit switches and ball valve position transmitters. ^'

The main procedure for the control system 35 is shown as a flow diagram in Fig. 3. Initially, the power is switched on 50 and the micro-processor unit 36 closes 51 the flowline valve 20, gaslift valve 28 and downhole gaslift valve 10 via output lines 44, 45, 47 and resets 51 its internal timers. The control system waits for a

start command 52 and on receiving the start command 52 starts 53 the main procedure. If the inputs received on the input lines 43 are all within the preset boundaries, the procedure waits for a signal 54 to confirm that the plunger 13 is its lowermost position within the tubing 3. When this is confirmed the processor 36 starts 55 a plunger fall back counter T5 and executes a plunger on bottom procedure 56.

The plunger on bottom procedure 56 calculates when the plunger is at the desired depth in the tubing 3. It can designed to be used in conjunction with a downhole pressure transmitter (DPT gauge) and calculates the fluid level by the intersection of two gradient lines, the oil gradient line and the gas gradient line. The free fall velocities of the plunger in the oil and gas are input values in the calculations and are a function of oil and gas viscosity, geometry of the well and type of plunger. Once the plunger is at the bottom of the tubing, the procedure 56 transfers control to the main procedure.

The next stage is the execution of a slug optimisation procedure 65. The slug optimisation procedure 65 calculates the optimum time at which to initiate the producing phase of the well cycle. After arrival of the plunger at the stop collar 12 the well is in a position to produce. This can commence immediately or be delayed until in-flow into the well ceases to meet a critical value. The rate of increase in bottom hole pressure is indicative of beneficial in-flow of hydrocarbons into the casing 2. As the hydrostatic head in the tubing 3 increases, back pressure is applied to the reservoir and in-flow decreases. The point where in-flow ceases to be linear is the time to

initiate the producing phase of the well cycles. Thus when the rate of change of pressure is less than a pre- set value (C3), injection of gaslift gas into the tubing through the gaslift valve 10 will commence. A gaslift open timer can be modified to adjust the plunger upward velocity to its optimum value. Optimisation is done by comparing upward velocity against produced volume for a fixed number of cycles.

When the slug optimisation procedure 65 is completed, control returns to the main procedure to execute a produced volume procedure 72. The function of the produced volume procedure 72 is to calculate the produced volume from the well by gauging the volume delivered by each cycle of the plunger 13 on its upward journey. The absolute value is not important to the optimisation routine as the prime function is to achieve a maximum value. The metering calculation should be accurate to field management requirements and is typically of the order of +/-5%. The procedure checks for a condition that the tubing head pressure at a distinct part of the well cycle exceeds a pre-set value (P2). This value P2 is set for each individual well as experience dictates. Once the pressure has exceeded the threshold value P2, the system assumes that liquid is being delivered by the system and commences to compute and accumulate the volume delivered to a data register Al in the data logging unit 40. The computed volume is the integral of the differential pressure with respect to the duration of the differential. Once the value P2 decreases to less than the threshold pressure, the procedure 72 is terminated and control is returned to the main procedure.

The calculations involved in the procedures 56, 65, 72 are all conventional text book calculations.

The main procedure starts 79 a blowdown counter T4. If counter T4 is up 80, the flowline valve is closed 81 and when it is confirmed that the flowline valve is closed 82, an optimisation procedure 83 is run and the operational cycle repeats itself starting from step 54 on the main procedure.

The optimisation procedure 83 compares the current cycle produced volume with the previous cycle produced volume and alters the necessary parameters to try to obtain optimisation of the produced volume.

If at any time during operation of the main procedure an unacceptable or unsafe condition in the production system 1 is detected, a safety shutdown routine 84 can be commenced.

The invention has the advantage of extending the scope and capability of this type of production systems. In addition, the optimisation in the system can reduce the gaslift requirement by as much as 60% and production rates can be increased by up to 50% or more through the improved gaslift performance.

Also, such a control system should be self optimising and should self adjust as reservoir performances change.

The control system also has the advantage that production can be controlled by using suitably modified procedures in order to control the production to that required.

Modifications and improvements may be incorporated without departing from the scope of the invention.