Case Pressure and pipeline control – increased oil production
Processing pressures are closely related to production capacity. Control of inlet separator pressure, and possibly also upstream pressures on templates, wellheads and downhole, are therefore of high interest when production optimization is addressed.
Gas capacity control
With this controller proposal, we assume that total production capacity is limited by the gas capacity, or more specifically the compressor capacity. As the inlet separator pressure is usually controlled by a standard PIC that manipulates the compressor speed, this means that the speed (or turbine efficiency) has reached its maximum, giving a separator pressure on or above the setpoint value of the PIC. In order to prevent pressures close to the flare limit, the operator may choose to back off production form certain wells or well clusters. However, backing off represents production decrease, and reducing too much will cause the turbine to decrease speed or efficiency, and the plant is no longer constrained by the compressing capacity.
In order to limit the production reduction, and in order to maintain the highest possible pressure at all times, Cybernetica propose a model based controller. The figure below indicates possible manipulated variables with green arrows, and possible controlled variables with red markers. This specific plant configuration indicates subsea wells routed to a common template, in addition to “disturbances” from other wells (“Disturbance” block), whose details are not shown. As a minimum controller configuration for this specific plant example, we should select at least one subsea choke (swing producer) together with the topside choke as manipulated variables. We are then able to control both the separator pressure and the common template (flowline) pressure. The need for inlet separator pressure control is explained above, and the template pressure is included in the MPC controller in order to keep fixed downstream conditions for the non-used common template wells.
Example of operation:
Imagine a reduction in flow from one or more “Disturbance” wells. This will reduce the separator pressure, and actions must be taken in order to remain on the maximum capacity constraints of the gas processing train. Assume that one subsea choke (e.g. the leftmost of the four chokes marked in the picture) can be manipulated automatically in addition to the cluster topside choke. The MPC controller predicts the response of the “Disturbance” wells, and compensates by opening the topside choke for the selected swing cluster. This will obviously increase the pressure of the separator, but it will also decrease the template pressure. We want to avoid the template pressure decrease because of the remaining cluster wells. The controller should therefore also open the selected (leftmost) subsea choke to compensate for the topside choke. However, using the subsea choke will also influence on the inlet separator pressure. We therefore realize that the 2×2 controlling scheme has strong interactions, which motivates for model based control.
The above example could be extended by including several subsea chokes in the MPC application. In the example figure, we have marked all four subsea chokes as possible manipulated variables. We then get more manipulated variables than setpoint controlled variables, which can be handled by some kind of priority hierarchy for the selected chokes. Alternatively, all subsea chokes except from one can be given ideal resting values (steady state values), and thus only be used dynamically to improve the dynamic response.
Deduction well testing
Subsea wells producing towards a common template or flowline will typically be tested by a deduction methodology. Having installed the MPC application described above, it could even be used for test purposes. The choke for the selected well to be tested will be throttled manually by the operator. The controller should keep the template pressure at setpoint, in order to ensure that oil-, gas- and water flow from the non-tested cluster wells remains constant. This could be done by manipulating the topside flowline choke. In this situation, inlet separator pressure is not considered as a controlled variable, and the controller structure will be a SISO (single input – single output) system. However, “feed-forward” from the choke of the tested subsea well is included. The concept is illustrated in the figure below.
An alternative approach could be to skip control of template pressure, and obtain non-changed flow conditions for the non-tested wells by controlling their corresponding downhole pressures to fixed values. In this case, all subsea chokes except for from the one for the tested well, will be used by the MPC application.
Mature fields – decreasing reservoir pressure
For mature fields, production capacity is restricted by the reservoir pressure, and production- and subsea chokes are typically fully open in order to minimize the flow resistance. If possible, effort should be made in order to minimize the processing pressure, e.g. the inlet separator pressure, while at the same time respecting constraints in the separator- and compressor trains. As the MPC decreases the inlet separator pressure, the (export) compressor speed increases, which both increases the gas flow and decreases the suction pressure. The delivery pressure of the upstream recompressor decreases, and obviously both flows and pressures in the entire separator- and compressor trains are altered. To ensure safe operations of all basic PI(D) controllers during changing feed conditions, and to fulfill the final oil specifications (RVP), a multivariable MPC application is required, which are using several PIC and LIC setpoints as manipulated variables.
For some production facilities, reservoir pressures may have decreased so much that production of liquids is impossible without some kind of artificial lift. Recirculated gas is then injected in the well bottoms in order to reduce the density of the fluids and thus the static pressure drop along the wells. Alternatively, this may be viewed as pressure reduction in the wellbore, in order to increase drawdown.
The total available amount of gas should now be distributed among the producing wells in order to maximize the total flow of oil. An MPC application will calculate this optimal distribution, which also could change dynamically because of time varying GOR and GLR for different wells.