RU2598661C2 - Pressure control during drilling operations with the help of correction used in preset conditions - Google Patents

Abstract

FIELD: oil and gas industry.

SUBSTANCE: group of inventions relates to oil and gas industry, in particular, to equipment and works in drilling wells with control of pressure. To implement the method: determine required setting pressure in the well, add a correction to the setting pressure if the actual pressure in the well deviates from the setting value by preset value, and adjust the flow rate control device in such a way that the actual pressure in the well becomes closer to the setting one taking the correction into account. Well system may include flow rate control device, which controllably limits the flow rate from the well, and a control system, which determines the required setting pressure in the well, compares the setting value to the actual pressure in the well and, at the specified level of deviation of the actual pressure in the well from the setting value, adds a correction to the setting value, due to which the control system regulates the flow rate control device and therefore brings the actual pressure in the well to the set pressure value with the correction.

EFFECT: higher accuracy of pressure regulation is achieved.

20 cl, 6 dwg

Description

Technical field

The present invention generally relates to the equipment used and the work performed during drilling of underground wells, and in particular, in the example below, the present invention provides pressure control while drilling, applying the correction to the set pressure value in accordance with certain predetermined conditions.

State of the art

It is known to control the pressure in the well by adjusting the level of pressure applied to the well at or near the surface. This applied pressure can be generated by various sources, one or several, for example, back pressure generated by the throttle in the mud return line, pressure generated by a special back pressure pump, and / or pressure drawn from the riser to the mud return line.

Therefore, it is clear that in the technology of pressure regulation during drilling constant improvements are needed.

A brief description of the graphic materials

In FIG. 1 is a partial sectional view of a well drilling system and a method associated with this system that can implement the principles of the present invention.

In FIG. 2 schematically shows another example of a well drilling system and corresponding method.

In FIG. 3 schematically shows a pressure and flow control system that can be used with the system and method of FIG. 1 and 2.

In FIG. 4 is a flowchart of an example of a method for controlling downhole pressure in which the principles of the present invention can be implemented.

In FIG. 5A and B are flowcharts of another example of a method for controlling downhole pressure.

Detailed Disclosure of Invention

In FIG. 1 illustrates a well drilling system 10 and a method associated with this system in which the principles of the present invention can be implemented. However, it should be clearly understood that the system 10 and this method are just one example of putting into practice the ideas of the present invention, and a wide range of other examples are possible. Therefore, the scope of the present invention is by no means limited to the details of the system 10 and method disclosed in the present description and / or illustrated in the drawings.

In the example of FIG. 1, well 12 is drilled by a rotating drill bit 14 at the end of drill string 16. Drilling fluid 18, commonly referred to as “drilling fluid”), circulates down the drill string 16, from drill bit 14 and up through the annular space 20 between the drill string and the wall of the well 12 to cool the drill bit, lubricate the drill string, remove debris, and provide measurements to control pressure in the wellbore. A non-return valve 21 (typically a poppet check valve) prevents the drilling fluid 18 from flowing up the drill string 16 (for example, in the manufacture of joints in the drill string).

Well pressure control is very important in variable pressure drilling and other types of drilling operations. Preferably, the pressure in the well is precisely controlled to prevent excessive loss of fluid due to withdrawal into the geological formations surrounding the well 12, undesired fracturing, undesirable influx of formation fluids into the well, etc.

In a typical case of pressure-controlled drilling, it is required to maintain the pressure in the well slightly higher than the pore pressure of the formation through which the well passes, not exceeding the pressure of the fracturing. This technology is especially useful in situations where the interval between pore pressure and burst pressure is relatively small.

In a typical case of drilling with negative differential pressure, it is required to maintain the pressure in the well slightly lower than the pore pressure, thereby obtaining a controlled flow of fluid from the formation. In a typical case of drilling with positive differential pressure, it is required to maintain the well pressure somewhat higher than the pore pressure, thereby preventing (or at least restricting) the flow of fluid from the formation.

Nitrogen or other gas — or other light fluid — can be added to drilling fluid 18 to control pressure. Such a technology is useful, for example, in drilling operations with negative differential pressure.

In system 10, additional control of the pressure in the well is achieved due to the fact that the annular space 20 is sealed (for example, by isolating it from communication with the atmosphere and allowing an increase in pressure in the annular space on the surface or in the surface layer) and a rotating deflecting preventer (FOP) 22 is used VOP 22 seals the drill string 16 above the wellhead 24. Although not shown in FIG. 1, drill string 16 extends upward through VOP 22 to connect, for example, to a drill rotor (not shown), riser pipe 26, a drill pipe (not shown), top drive, and / or other conventional drilling equipment.

The drilling fluid 18 leaves the wellhead 24 through a valve 28 in a line that communicates with the annular space 20 below the GPO 22. Further, the drilling fluid 18 flows through the drilling fluid return lines 30, 73 to the throttle manifold 32 containing backup throttles 34 (of which only one can be used at a time). Back pressure is applied to the annular space 20 by means of an adjustable restriction of the flow of fluid 18 through the working choke (chokes) 34.

The more limited the flow through the throttle 34, the higher the back pressure applied to the annular space 20. Thus, the borehole pressure (e.g., bottom hole pressure 12, pressure at the casing shoe, pressure at the level of a particular formation or belt, etc. ) can be conveniently controlled by changing the back pressure applied to the annular space 20. To determine what pressure applied to the annular space 20 on or near the surface will lead to the required borehole pressure, it can be used Wang, as fully disclosed below, the hydraulic model, so that the operator (or automated control system) may easily determine how to adjust the applied annulus at or near the surface pressure (which can easily be measured) to obtain the desired downhole pressure.

The pressure applied to the annular space 20 can be measured on or near the surface by a series of pressure sensors 36, 38, 40, each of which communicates with the annular space. The pressure sensor 36 senses pressure below the GPO 22, but above the block 42 blowout preventers (PVP). The pressure sensor 38 senses the pressure at the wellhead below block PVP 42. The pressure sensor 40 senses the pressure in the lines 30, 73 return of the drilling fluid before the throttle manifold 32.

Another pressure sensor 44 senses pressure in the riser pipe 26. The next pressure sensor 46 senses the pressure after the throttle manifold 32, but up to the separator 48, the vibrator 50 and the mud settler 52. Additional sensors include heat-sensitive elements 54, 56, Coriolis flowmeter 58 and flowmeters 62, 64, 66.

Not all of these sensors are needed. For example, the system 10 may contain only two of the three flowmeters 62, 64, 66. However, the signals of all available sensors supplied to the input of the hydraulic model can be useful in determining what should be the pressure applied to the annular space 20 during drilling .

If necessary, other types of sensors can be used. For example, flowmeter 58 need not be a Coriolis flowmeter, since a turbo flowmeter, an acoustic flowmeter, or another type of flowmeter may be used instead.

In addition, the drill string 16 may contain its own sensors 60, for example, for direct measurement of borehole pressure. These sensors 60 can be known to those skilled in the art for measuring pressure during drilling (IMDB), measuring while drilling (IMD) and / or logging while drilling (IMD). These drill string sensor systems generally provide at least pressure measurements and can also provide temperature measurements, drill string characterization (e.g. vibration, drill bit load, stick-offset, etc.), formation characteristics (e.g. resistivity, density, etc.) and / or other measurements. To transmit measurements of downhole sensors to the surface, various types of wire or wireless telemetry can be used (acoustic, hydro-pulse, electromagnetic, etc.).

If necessary, additional sensors may be included in system 10. For example, another flowmeter 67 can be used to measure the flow rate of fluid 18 exiting the wellhead 24, another Coriolis flowmeter (not shown) can be connected immediately before or after the mud pump 68, etc.

If necessary, fewer sensors may be included in system 10. For example, the performance of the mud pump 68 may be determined by the number of strokes of the pump piston, instead of using a flow meter 62 or any other flow meter.

Note that the separator 48 may be a 3- or 4-phase separator or gas separator for a drilling fluid (sometimes called a “mud degasser”). However, it is not necessary to use separator 48 in system 10.

The drilling fluid 18 is pumped through a riser pipe 26 inside the drill string 16 by the mud pump 68. The pump 68 receives the fluid 18 from the mud settler 52 and feeds it through the discharge manifold 70 to the riser 26. After that, the fluid 18 circulates down the drill string 16 up through the annular space 20, through the mud return lines 30, 73, through the throttle manifold 32, and then through the separator 48 and vibrator 50 to the mud settler 52 for conditioning and recirculation.

Note that in system 10, as described above, throttle 34 cannot be used to regulate backpressure applied to annular space 20 to control borehole pressure if fluid 18 does not flow through the throttle. In conventional positive differential pressure drilling operations, the absence of fluid flow 18 occurs whenever, for example, connections are made in the drill string 16 (for example, when adding another section of the drill pipe to the drill string when the well 12 is drilled deeper), and lack of circulation requires that the borehole pressure be regulated exclusively by the density of the fluid 18.

In system 10, however, fluid flow 18 through throttle 34 can be maintained even when fluid is not circulated through drill string 16 and annular space 20 during connections made in the drill string. Thus, pressure can still be applied to the annular space 20 by restricting the flow of fluid 18 through the throttle 34, even though a separate backpressure pump may not be used.

When fluid 18 does not circulate through drill string 16 and annulus 20 (for example, when connections are made in the drill string), fluid flows from pump 68 to throttle manifold 32 through bypass line 72, 75. Thus, fluid 18 can bypass riser conduit 26, drill string 16, and annulus 20 and may flow directly from pump 68 to mud line 30, which still communicates with annulus 20. Thus, restricting this flow to dross Lemma 34 will create pressure applied to the annular space 20 (for example, in the typical case of pressure-controlled drilling).

As shown in FIG. 1, both the bypass line 75 and the mud return line 30 communicate with the annular space 20 through one line 73. However, the bypass line 75 and the mud return line 30 may instead separately be connected to the wellhead 24, for example, using an additional gate valve (e.g. below GP 22); in this case, each of the lines 30, 75 will directly communicate with the annular space 20.

This may require the installation of additional pipelines at the location of the rig, but the effect on the pressure in the annular space will be essentially the same as when connecting the bypass pipe 75 and the return line 30 of the drilling fluid to the common pipe 73. Thus, there should be it is clear that many different arrangements of elements of the system 10 can be used, which nevertheless fall within the scope of the present invention.

The flow rate of the fluid 18 through the bypass line 72, 75 is controlled by a throttle or other type of flow regulator 74. A pipe 72 is connected upstream of the bypass flow controller 74, and a pipe 75 is connected upstream of the bypass flow controller.

The flow of fluid 18 through the riser pipe 26 is essentially controlled by a valve or other type of flow control 76. Since fluid flow rates 18 through riser and bypass lines 26, 72 are useful in determining how these flow rates affect well pressure, flow meters 64, 66 are introduced into these lines, as shown in FIG. one.

However, the flow rate through the riser pipe 26 can be determined even when using only flow meters 62, 64, and the flow through the bypass pipe 72 can be determined even when using only flow meters 62, 66. Thus, it should be understood that the system 10 does not have to contain all sensors shown in FIG. 1 and disclosed herein, but instead, the system may comprise additional sensors, various combinations and / or types of sensors, etc.

In the example of FIG. 1 bypass flow regulator 78 and flow limiter 80 can be used to fill the riser pipe 26 and the drill string 16 after making the connection in the drill string and to balance the pressures in the riser pipe and drilling fluid return lines 30, 73 before opening the flow controller 76. Otherwise, the sudden - until the pipe 18 of the riser and the drill string 16 is filled with fluid 18 and the pressure in them increases - the opening of the flow controller 76 can cause undesirable transient pressure fluctuations in the annular space 20 (for example, due to a temporary lack of flow to the throttle manifold 32 in the process of filling the riser pipe and drill string with fluid, etc.).

The opening of the riser bypass flow controller 78 after the connection is made, allows the fluid 18 to fill the riser pipe 26 and the drill string 16, while the substantially predominant portion of the fluid continues to flow through the bypass pipe 72, thereby allowing continuous, controlled application of pressure to the annular space 20. After the pressure in the riser pipe 26 equalizes with the pressure in the mud return lines 30, 73 and in the bypass pipe 75, the flow controller 76 t be opened, and further, the flow regulator 74 may be closed for slow redirect a significant portion of the fluid 18 from the bypass conduit 72 into the conduit 26 of the riser.

A similar process, but in reverse order, can be performed in the drill string 16 prior to making the connection — to gradually redirect the fluid flow 18 from the riser pipe 26 to the bypass pipe 72 in order to prepare the addition of drill pipes to the drill string 16. That is, the regulator 74 the flow rate can be gradually opened to slowly redirect a larger portion of the fluid 18 from the riser pipe 26 to the bypass pipe 72, and then the flow control 76 can be closed.

Note that the flow controller 78 and the flow limiter 80 can be combined into one element (for example, a flow controller with an integrated flow limiter), and the flow controllers 76, 78 can be combined into one flow controller 81 (for example, into one choke, which gradually open for slow filling and pressurization of the pipe 26 of the riser and the drill string 16 after completing the connection of the drill pipe and, further, fully open to ensure maximum flow rate during drilling).

However, since typical conventional derricks are equipped with a flow control 76 in the form of a valve in the discharge manifold 70 and the use of a riser valve is a common drilling practice, individually controlled flow control 76, 78 prevent the use of a flow control 76. The flow controllers 76, 78 below are sometimes referred to generally as a single flow control 81, but it should be understood that the flow control 81 may comprise separate flow controllers 76, 78.

Another example is shown in FIG. 2. In this example, a flow controller 76 is introduced upstream of the discharge manifold 70 of the oil rig. This arrangement has certain advantages, for example, it is not necessary to modify the discharge manifold 70 of the oil rig or the pipeline between the manifold and the drill pipe; the riser drain valve 82 can be used to purge the riser 26, as in standard drilling operations (there is no need to change the methodology involving the drilling crew), etc.

A flow controller 76 may be connected between the mud pump 68 and the discharge manifold 70 using, for example, quick-connect locks 84 (eg, snap-on couplings, etc.). This will conveniently adapt the flow controller 76 to be included in various mud pump lines.

Instead of using the traditional riser valve in the discharge manifold 70 of the oil rig, a specially adapted fully automated flow controller 76 (for example, automatically controlled by the controller 96 shown in Fig. 3) can be used to control the flow through the riser pipe 26. In General, the flow controller 81 can be performed, rather, not for the purpose of traditional drilling, but according to the customer’s conditions for such an application as disclosed in the present description (for example, for regulating the flow rate through the riser pipe 26 in connection with the distribution of the fluid 18 between the riser pipe and the bypass pipe 72 to thereby regulate the pressure in the annular space 20, etc.).

In the example of FIG. 2, a remote-controlled valve or other flow controller 160 is optionally used to redirect the fluid flow 18 from the riser pipe 26 to the mud return line 30 after the throttle manifold 32, in order to transmit signals, data, commands, etc. downhole tools (for example, the layout of the bottom of the drill string of Fig. 1, which includes sensors 60, and other equipment, including downhole turbine engines, deflecting devices, deviation controllers, etc.). The controller 160 is controlled by telemetry by the controller 162, which can encode information in the form of a sequence of flow deviations determined by the downhole tools (for example, a certain decrease in flow rate through the downhole tool will result from the corresponding redirection of the flow by the controller 160 from the riser pipe 26 to the mud return line 30).

A suitable telemetry controller and a suitable remotely controlled flow controller are available on the GEO-SPAN (TM) system supplied by Halliburton Energy Services, Inc. The telemetry controller 162 may be connected to an INSITE (TM) system or to another data collection and control interface 94 in the control system 90. However, other types of telemetry controllers and flow controllers can be used without departing from the scope of the present invention.

Note that each of the flow controllers 74, 76, 78 and throttles 34 are preferably remotely and automatically controlled so as to maintain the required borehole pressure while maintaining the required pressure in the annular space on or near the surface. However, any (any) one or more of these flow controllers 74, 76, 78 and throttles 34 may (may) be manually controlled without departing from the scope of the present invention.

A pressure and flow control system 90 that can be used in connection with the system 10 and related methods of FIG. 1 and 2, is shown in FIG. 3. The control system 90 is preferably fully automated, although some human intervention can be used, for example, to protect against abnormal operation, run certain programs, adjust parameters, etc.

The control system 90 comprises a hydraulic model 92, a data acquisition and control interface 94, and a controller 96 (e.g., a Programmable Logic Controller or PLC, appropriately programmed computer, etc.). Although these elements 92, 94, 96 are shown in FIG. 3 individually, some or all of them can be combined into one element, or the functions of the elements can be distributed among additional elements, or other additional elements and / or functions, etc. can be provided.

The hydraulic model 92 is used in the control system 90 to determine the required pressure in the annular space on the surface or in the surface layer, ensuring the achievement of the required borehole pressure. To make this determination, hydraulic model 92 uses, for example, well geometry data, fluid properties, information from neighboring wells (e.g., geothermal gradient, pore pressure gradient, etc.), as well as sensor data in real-time received through the interface 94 data collection and management.

Thus, there is a continuous two-way exchange of data and information between the hydraulic model 92 and the data acquisition and control interface 94. It is important to understand that the data acquisition and control interface 94 works to maintain a substantially continuous real-time data stream from sensors 44, 54, 66, 62, 64, 60, 58, 46, 36, 38, 40, 56, 67 to the hydraulic models 92, so that the hydraulic model receives the information that it needs to adapt to changing conditions and to adjust the required pressure in the annular space, and the hydraulic model works in order to substantially continuously provide the interface for data collection and control of the required pressure in annular space.

Suitable hydraulic models for use as the hydraulic model 92 in the control system 90 are REAL TIME HYDRAULICS (TM) or GB SETPOINT (TM) supplied by Halliburton Energy Services, Inc., Houston, Texas, USA. Another suitable hydraulic model is marketed under the trade name IRIS (TM), and another is supplied by SINTEF, Trondheim, Norway. Any suitable hydraulic models may be used in the control system 90 in accordance with the teachings of the present invention.

Suitable data collection and control interfaces for use as a data collection and control interface 94 in the control system 90 are SENTRY (TM) and INSITE (TM) supplied by Halliburton Energy Services, Inc. Any suitable data acquisition and control interface may be used in the control system 90 in accordance with the teachings of the present invention.

The controller 96 operates to maintain the desired set pressure in the annular space by controlling the operation of the mud return throttle 34 and other devices. For example, the controller 96 may also be used to control the operation of the riser flow controllers 76, 78 and the bypass flow controller 74. Thus, the controller 96 can be used to automate the processes of redirecting the fluid flow 18 from the riser pipe 26 to the bypass pipe 72 before making the connection in the drill string 16; further, to redirect the flow from the bypass pipe to the riser pipe after the connection is made and, further, to resume normal circulation of the drilling fluid 18. Again, these automated processes may not require human intervention, although human intervention can be used, for example, to start each process in turn, to manually control system elements, etc.

Validation and data prediction techniques may be used in system 90 to protect against the use of erroneous data, to ensure that measured values are consistent with predicted values, etc. Suitable techniques for confirming and predicting data are disclosed in international application No.PCT / US11 / 59743, although other techniques may be used if necessary.

In the past, when the adjusted value of the required pressure in the annular space was transmitted from the data acquisition and control interface 94 to the controller 96, the controller used the required pressure in the annular space as a setting value and adjusted the throttle 34 to maintain (e.g., increase or decrease as resistance to flow through the throttle) setting pressure in the annular space 20. The throttle 34 was closed more to increase the resistance to flow, or opened I have more to reduce the flow resistance.

The pressure setpoint was maintained by comparing the pressure setpoint with the pressure measured in the annular space (for example, with the pressure measured by any of the sensors 36, 38, 40) and reducing the flow resistance through the throttle 34 if the measured pressure was higher than the pressure setpoint , or increasing resistance to flow through the throttle if the measured pressure is below the set pressure value. Unfortunately, the throttle control, in a typical case, was determined by the proportional-integral-differential (PID) controller, therefore (depending on the input coefficients of the PID controller) the throttle could easily be overshooted, or under-regulated, or a long period of time was required to complete the series increments necessary to bring the throttle to its final position, in which the throttle is able to maintain the required pressure in the annular space.

One of the reasons for this situation was that the coefficients used in the PID controller remained the same throughout the entire drilling operation and were selected for use in normal, relatively stable conditions. These same coefficients were not ideal when used in rapidly changing conditions, for example, when a sudden change in pressure or flow rate.

But in the example of the method more fully disclosed below, such rapid changes in drilling conditions can be reacted more quickly by adding corrections to the set pressure value. Adding corrections to the set pressure value in the process of adjusting the throttle 34 leads to a more rapid achievement of the flow rate corresponding to control in changing drilling conditions. When relatively stable conditions are restored, the correction can be removed, and the controller 96 will adjust the throttle 34 to maintain the required set pressure value in the well.

Turning now to FIG. four; it presents in the form of a simplified flowchart a method 100 for controlling pressure in a well. Method 100 may be used with the system 10 disclosed above, or with other systems.

In an initial step 102 of method 100, a desired pressure setting value is determined. In the system 10, this pressure setting value corresponds to the pressure in the annular space 20 at or near the wellhead 24. This pressure can be measured at any point up to the throttle manifold 32.

However, in other examples, the pressure setting value may be set for a location other than wellhead 24. For example, the pressure setting value can be set in the depth of the well (for example, at the casing shoe, at the level of a particular formation, in the bottom of the well 12, etc.). In this case, measurements of the actual pressure on the surface or in the well can be used by the controller 96 to compare with the set pressure value.

At 104, the actual pressure in the well is measured. As mentioned above, pressure measurement can be performed anywhere in the well. For example, surface pressure sensors 36, 38, 40, or downhole sensors 60 (or subsea sensors) may be used to measure pressure.

In step 106, the actual pressure in the well deviates from the desired pressure setting. In system 10, a comparison of actual well pressure with a desired one is performed by controller 96.

With relatively stable drilling conditions, some deviations of the actual well pressure from the required one should be expected, and the controller 96 automatically adjusts the throttle 34 to minimize (or, ideally, eliminate) these deviations. However, when large deviations occur, method 100 provides an additional “addition” to the set pressure value (in the direction in which the actual pressure should be changed in order to get closer to the desired pressure value), so that the controller 96 will quickly adjust the throttle 34 to the flow rate at which actual pressure is equal to or close to required.

In step 108, a correction is added to the pressure setpoint if the difference between the actual and the desired pressure exceeds a predetermined value. This predetermined value is selected so that, with relatively stable drilling operations, the correction is not added to the set pressure value. The correction is added only when the difference between the actual and the required pressure is large enough.

In step 110, the controller 96 adjusts the throttle 34 so as to bring the actual pressure closer to the set pressure value with the correction added in step 108. For example, if the actual pressure is low enough compared to the set pressure value, a positive correction can be added to this set value. so that the controller 96 controls the throttle 34 so that initially to limit the flow of fluid 18 from the annular space 20 more than would be if the controller used only the installation pressure value for regulating throttle operation. Conversely, if the actual pressure is sufficiently large compared to the set pressure value, a negative correction can be added to this set value so that the controller 96 transfers the throttle 34 to a lower initial restriction of the flow of fluid 18 from the annular space 20 than would be if the controller used only the set pressure value to regulate the operation of the throttle.

At step 112, when relatively stable drilling operations are resumed, the correction is no longer applied. If there are no large deviations triggering the application of the correction, the correction is removed so that the controller 96 again controls the throttle 34 to maintain the actual pressure at the level of the required pressure setting (without correction).

Now let us turn to FIG. 5A and B; it is presented in more detail in the form of flowcharts an example of the method 100. The example of FIG. 5A and B are just one instance of applying the principles of the present invention to a particular drilling situation, but the principles of the present invention can be beneficial in a wide variety of other drilling situations, and it should be clearly understood that the scope of the present invention is by no means limited to any details of the system 10 or method 100 depicted in the drawings or disclosed in the present description.

The block diagrams of FIG. 5A and B present a program called “Lead Chokes”, indicating that it is used to quickly transfer the throttle (s) 34 to a flow rate corresponding to maintaining the actual pressure at the desired pressure setting value. This program is used in a drilling situation where a sudden drop in flow through the throttle 34 causes a sudden large pressure drop in front of the throttle. Such a situation may arise, for example, in the event of a sudden drop in the flow rate from the mud pump 68, in the event of a malfunction or abnormal operation of another flow controller, with large losses of fluid in the well, etc.

The following variables are used in the Lead Chokes program:

WHP is the actual pressure measured in the annular space 20 at the mouth 24 or near the mouth 24 in front of the throttle 34;

WHP_Target - required set pressure value issued by hydraulic model 92;

CD_Hydrostatic - hydrostatic pressure at the depth of regulation in the well 12 (the depth at which it is required to maintain the required pressure);

CD_Target - required pressure (hydrostatic plus friction pressure loss, if any) at the depth of regulation;

TurhOffLeadChokesWithin - deviation of the actual pressure from the required pressure setting, below which no correction is added to the required pressure setting;

Pumps_Down_Offset - A correction selected specifically for the drilling situation, in which the flow rate from the mud pump 68 suddenly drops;

lnjection_Flow_Rate is the flow rate of the fluid 18 pumped into the drill string 16;

Delta_Flow - change in the injection rate;

Delta_Time - transition time between the current injection rate and the previous injection rate;

Rate_Change - change in the ratio of injection flow to transition time;

FlowRateChangeThreshold - change in flow per unit time, above which a correction is prescribed;

LeadChokesStatus - indicates whether to add a correction to the required pressure setting;

LeadChokesOffset - the correction applied to the required set pressure value as a result of the Lead Chokes program;

CurrentMaxFlowRateChange - maximum flow rate change during program execution;

LastMaxFlowRateChange - previous maximum flow rate change;

Previous_Flow - previous expense used in the program;

Previous_Flow_Timestamp - recording time of the previous expense;

PreviousLeadChokesOffset - the previous correction applied to the required pressure setting value;

PreviousLeadChokesStatus is the previous indicator showing whether a correction has been added to the required pressure setting.

Those skilled in the art will appreciate that the addition of an amendment to the Drive Chokes program shown in FIG. 5A and B, “starts” when the rate of change of the injection flow rate (Rate_Change) reaches or becomes greater than the set level (FlowRateChangeThreshold), and the measured actual pressure (WHP) is less than the required pressure setting value (WHP_Target) by the set value (TurhOffLeadChokesWithin). If these (and other) conditions are met, then a correction (LeadChokesOffset) is added to the required pressure setting.

The correction (LeadChokesOffset) may be a pre-selected correction (Pumps_Down_Offset) for this particular drilling situation. Alternatively, if the adjusted pressure value is greater than the required pressure at the control depth (CD_Targef) minus the hydrostatic pressure at this depth (CD_Hydrostatic), then the correction can be reduced to the difference between the required pressure at the control depth and the hydrostatic pressure at this depth. This should reduce the likelihood that the throttle 34, after adding the correction to the set pressure value, will restrict the flow too much, so that overpressure will occur at the depth of regulation.

In other examples, other drilling situations may be reflected. For example, separate programs for fluid inflow, filtration, production of compounds in drill string 16, and for any other situation may be proposed. Thus, the scope of the present invention is not limited to the application of an amendment only in the event of a sudden drop in flow.

It can now be fully understood that the invention disclosed above provides a significant improvement in the technique for controlling pressure during drilling. The method 100 can be applied in regulating the throttle 34 necessary to quickly restore the required pressure in the well. In the example disclosed above, a correction can be added to the desired installation pressure value in the well 12 to more quickly transfer the throttle 34 to a flow rate corresponding to maintaining the required pressure in the well.

Above, a method 100 for controlling pressure in a well 12 during drilling is disclosed. In one example, method 100 includes the following steps: determining a desired well pressure setting; a correction is added to the set pressure value in the well if the actual pressure in the well deviates from the set pressure value by a predetermined amount; and adjust the flow control device (for example, throttle 34) so as to bring the actual pressure in the well closer to the set value of the pressure in the well taking into account the correction.

The required installation pressure value in the well can be obtained at the output of the hydraulic model 92.

Correction can also be added at a given rate of change in flow. This predetermined rate of change in flow rate may include a drop in flow rate through the flow controller (e.g., throttle 34).

The method may also include a step in which the correction is removed when the actual pressure in the well deviates from the set pressure value by an amount less than a predetermined value.

The flow control device may include a throttle 34, limiting the flow of fluid from the well 12.

The method may also include the step of adjusting the flow control device so as to bring the actual well pressure closer to the set pressure value without correction before adding the correction to the set value.

The borehole system 10 is also disclosed above. In one example, the borehole system 10 may include a flow regulator that controls the flow rate from the well 12 in a controlled manner, and a control system 90 that determines the desired set pressure value in the well compares this set pressure value with the actual pressure in the well and, at a given level of deviation of the actual pressure in the well from the set pressure, adds a correction to the required set pressure. The control system 90 controls the flow control device and thus brings the actual well pressure closer to the adjusted pressure value.

In another example, the method 100 for regulating the pressure in the well 12 while drilling may include the following steps: adjust the flow control device and thereby bring the actual pressure in the well closer to the desired pressure setting; then, a correction is added to the set pressure value in the well if the actual pressure in the well deviates from the set pressure value by a predetermined amount, then the flow control device is adjusted and thereby the actual pressure in the well is brought closer to the set pressure value taking into account the correction.

Although the various examples are disclosed above and each example has certain features, it should be understood that the specific feature of any example need not be used solely with this example. On the contrary, any features disclosed above and / or shown in the drawings may be combined with any of the examples, in addition to any other features, or in exchange for any other features of these examples. The individual features of the examples are not mutually exclusive. On the contrary, the scope of the present invention includes any combination of any features.

Although each example disclosed above contains certain combinations of features, it should be understood that all the features of the example need not be used. On the contrary, any signs disclosed above can be used without the simultaneous use of any other specific sign or signs.

It should be understood that the various embodiments disclosed herein can be applied in various orientations, for example, obliquely, inverted, horizontally, vertically, etc., and in various arrangements, without departing from the teachings of the present invention. Embodiments of the invention are disclosed merely as examples of the beneficial application of the teachings of the present invention, which is not limited to any specific details of these embodiments.

In the above description of representative examples, the terms of directions (for example, “above”, “below”, “upper”, “lower”, etc.) are used for convenience of reference to the accompanying drawings. However, it should be clearly understood that the scope of the present invention is not limited to any specific areas disclosed in the present description.

The terms “including”, “includes”, “comprising”, “contains” and similar terms are used in this description in a non-limiting sense. For example, if the system, method, device, device, etc. are described as “including” a particular feature or element, then a system, method, device, device, etc. may contain this feature or element and may also contain other features or elements. Similarly, the term “contains” is understood to mean: “contains, but not restrictively.”

Of course, a specialist, after careful consideration of the above description of characteristic embodiments of the present invention, will easily understand that numerous modifications, additions, replacements, deletions, and other changes can be made in specific embodiments, and such changes are contemplated by the principles of the present invention. For example, constructs disclosed as separate can be combined in other examples — and vice versa. Accordingly, the foregoing detailed description should be clearly understood as given only by way of illustration and example, and the spirit and scope of the invention are limited solely by the appended claims and their equivalents.

Claims (20)

1. A method of controlling pressure in a wellbore while drilling, comprising the following:
determine the required installation value of the pressure in the well;
a correction is added to the set pressure value in the well when the actual pressure in the well deviates from the set pressure value in the well by a predetermined amount; and
adjust the flow control device so as to bring the actual pressure in the well closer to the adjusted pressure value. 2. The method according to p. 1, in which the required installation value of the pressure in the well produces a hydraulic model. 3. The method according to p. 1, in which the addition of the amendments is also performed at a given level of change in flow. 4. The method according to p. 3, in which a predetermined rate of change in flow includes reducing the flow rate through the flow control device. 5. The method according to p. 1, additionally containing the following: the amendment is removed when the actual pressure in the well deviates from the set pressure in the well by an amount that is less than the specified value. 6. The method of claim 1, wherein the flow control device comprises a throttle limiting the flow rate of the fluid from the well. 7. The method according to claim 1, further comprising adjusting the flow control device to thereby bring the actual pressure in the well closer to the set pressure value without correction, before it is added. 8. A downhole system comprising:
a flow control device configured to limit the flow rate from the well in a controlled manner, and
a control system configured to determine the required set pressure in the well, compare the set pressure with the actual pressure in the well and add corrections to the required set pressure value for a given deviation of the actual pressure in the well from the set pressure, while the control system is configured to control the device flow control and, thus, approximation of the actual pressure in the well to the set pressure value with Rawka. 9. The system of claim 8, wherein the control system comprises a hydraulic model that is configured to provide the desired set pressure value in the well. 10. The system according to claim 8, in which the control system is configured to add corrections to the installation pressure value in the well also at a given rate of change in flow. 11. The system of claim 10, wherein the predetermined rate of change in flow rate includes reducing the flow rate through the flow rate control device. 12. The system according to claim 8, in which the control system is able to remove the correction when the actual pressure in the well deviates from the set pressure value by an amount that is less than the specified value. 13. The system of claim 8, wherein the flow control device comprises an automatically adjustable throttle. 14. The system of claim 8, wherein the control system is configured to adjust the flow control device so as to bring the actual pressure in the well closer to the set pressure value without correction when the actual pressure in the well deviates from the set pressure value by less than the set value. 15. The method of regulating the pressure in the well during drilling, comprising the following:
controlling a flow control device to bring the actual pressure in the well closer to the desired set pressure in the well;
then, a correction is added to the set pressure value in the well when the actual pressure in the well deviates from the set pressure value by a predetermined value; and
then adjust the flow control device so as to bring the actual pressure in the well closer to the adjusted pressure value. 16. The method according to p. 15, in which the desired installation pressure value in the well produces a hydraulic model. 17. The method according to p. 15, in which the addition of the amendments is also performed at a given level of change in flow. 18. The method of claim 17, wherein the predetermined rate of change in flow rate includes reducing the flow rate through the flow control device. 19. The method according to p. 15, further comprising the following: after adjustment, the correction is removed when the actual pressure in the well deviates from the set pressure value by an amount that is less than the specified value. 20. The method of claim 15, wherein the flow control device comprises a throttle limiting the flow rate of the fluid from the well.

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