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    • 专利摘要:
    USE OF BELOW WELL PRESSURE MEASUREMENTS DURING DRILLING FOR THE DETECTION AND MITIGATION OF INLET FLOWS. A well drilling system may include a hydraulic model which determines a modeled fluid friction pressure and a calibration factor applied to the modeled friction pressure. A well drilling method may include drilling a wellbore, circulating fluid through the wellbore during drilling, determining a calibration factor which is applied to a modeled fluid friction pressure, and control of drilling based at least in part on a change in calibration factor.
    公开号:BR112014013215B1
    申请号:R112014013215-1
    申请日:2012-11-05
    公开日:2021-05-04
    发明作者:James R. Lovorn
    申请人:Halliburton Energy Services, Inc；
    IPC主号:
    专利说明:

    TECHNICAL FIELD
    [0001] This exposure generally refers to equipment used and operations performed in conjunction with drilling an underground well and, in an example described below, more particularly provides for the use of pressure measurements below well during drilling for detection and the mitigation of inflows. BACKGROUND
    [0002] A hydraulic model can be used to control a drilling operation, for example, in a pressure managed, underbalanced, overbalanced or pressure controlled drilling. Typically, one objective is to keep the wellbore pressure at a desired value during the drilling operation. Unfortunately, an inflow into a wellbore during drilling can disrupt normal drilling operations and, if left unchecked, can lead to dangerous conditions.
    [0003] Therefore, it will be appreciated that improvements are continually needed in the technique of detecting and mitigating inflows during drilling operations. BRIEF DESCRIPTION OF THE DRAWINGS
    [0004] Figure 1 is a partially representative cross-sectional view of a well drilling system and an associated method, which can embody the principles of this exposition.
    [0005] Figure 2 is a representative schematic view of another example of the well drilling system and method.
    [0006] Figure 3 is a representative schematic view of a pressure and flow control system which can be used with the system and method of figures 1 and 2.
    [0007] Figure 4 is a representative drill profile, in which an inflow event is recorded.
    [0008] Figure 5 is a representative flowchart for a method of detection and mitigation of an input stream. DETAILED DESCRIPTION
    [0009] Representatively illustrated in figure 1 is a well drilling system 10 and an associated method, which can implement the principles of this exposition. However, it should be clearly understood that the system 10 and the method are merely an example of an application of the principles in this exposition in practice, and a wide variety of other examples are possible. Therefore, the scope of this exposition is not limited to the details of system 10 and a method described here and/or exposed in the drawings.
    [0010] In the example of Figure 1, a wellbore 12 is drilled by rotating a drill bit 14 on one end of a drill string 16. The drilling fluid 18, commonly known as mud, is circulated downward through of the drill string 16, out of the drillstring 14 and up through an annular space 20 formed between the drill string and the wellbore 12, in order to cool the drillstring, lubricate the drill string, remove cuts and provide a measure of wellbore pressure control. A check valve 21 (typically a vane type check valve) prevents a flow of drilling fluid 18 through the drill string 16 (e.g. when connections are being made to the drill string).
    [0011] A wellbore pressure control is very important in pressure managed drilling, and in other types of drilling operations. Preferably, the wellbore pressure is precisely controlled to prevent excessive fluid loss to the ground formation surrounding the wellbore 12, an unwanted fracturing of the formation, an unwanted inflow of formation fluids to the wellbore. well, etc.
    [0012] In a typical pressure managed drilling, it is desired to keep the wellbore pressure only slightly greater than a formation pore pressure penetrated by the wellbore, without exceeding a formation fracture pressure. This technique is especially useful in situations where the margin between pore pressure and fracture pressure is relatively small.
    [0013] In a typical underbalanced drilling, it is desired to keep the wellbore pressure somewhat lower than the pore pressure, thereby obtaining a controlled inlet flow of fluid from the formation. In a typical superbalanced drilling, it is desired to keep the wellbore pressure somewhat higher than the pore pressure, thereby avoiding (or at least mitigating) the inflow of fluid from the formation.
    [0014] Nitrogen or another gas, or another lighter weight fluid, may be added to drilling fluid 18 for pressure control. This technique is useful, for example, in underbalanced drilling operations.
    [0015] In system 10, additional control over wellbore pressure is achieved by closing the annular space 20 (for example, isolating it from communication with the atmosphere and allowing the annular space to be pressurized at or near the surface) using a rotation control device 22 (RCD). The RCD 22 forms a seal around the drill string 16 above the wellhead 24. Although not shown in Figure 1, the drill string 16 would extend upward through the RCD 22 for connection, for example, to a rotary table (not shown), a cane 26 tube line, a kelley (not shown), a top drive and/or other conventional drilling equipment.
    [0016] Drilling fluid 18 exits wellhead 24 through a side valve 28 in communication with annular space 20 below RCD 22. Fluid 18 then flows through mud return lines 30, 73 to a manifold of pressure regulator 32, which includes redundant pressure regulators 34 (of which only one could be used at a time). Back pressure is applied to annular space 20 by variably restricting fluid flow 18 through pressure regulator(s) 34.
    [0017] In other examples, flow control devices other than pressure regulators 34 can be used to apply back pressure to the annular space 20. For example, a valve or other type of flow control device can be used for restriction flow or flow diversion, so that the back pressure applied to the annular space 20 is regulated.
    [0018] In the example of Figure 1, the greater the restriction to a flow through the pressure regulator 34, the greater the back pressure applied to the annular space 20. Thus, a downhole pressure (for example, a pressure at the bottom of the wellbore 12, a pressure in a well casing nozzle below, a pressure in a particular formation or zone, etc.) can be conveniently regulated by varying the back pressure applied to the annular space 20. A hydraulic model can be used, as described further fully below, for the determination of a pressure applied to the annular space 20 at or near the surface, which will result in a desired downhole pressure so that an operator (or an automated control system) can readily determine how to regulate the pressure applied to the annular space at or near the surface (which can be conveniently measured) so as to obtain the desired downhole pressure.
    [0019] A pressure applied to the annular space 20 can be measured at or near the surface through a variety of pressure sensors 36, 38, 40, each of which is in communication with the annular space. A pressure sensor 36 detects pressure below the RCD 22, but above a burst prevention element (BOP) stack 42. The pressure sensor 38 detects a pressure in the wellhead below the BOP stack 42. The sensor pressure gauge 40 senses pressure in slurry return lines 30, 73 upstream of pressure regulator manifold 32.
    [0020] Another pressure sensor 44 senses the pressure in the cane tube line 26. Yet another pressure sensor 46 senses the pressure downstream of the pressure regulator manifold 32, but upstream of a separator 48, a vibrating screen 50 and a mud pit 52. Additional sensors include temperature sensors 54, 56, a Coriolis flow meter 58 and flow meters 62, 64, 66.
    [0021] Not all of these sensors are required. For example, system 10 could include only two of the three flowmeters 62, 64, 66. However, an input from all available sensors can be useful for the hydraulic model in determining what pressure should be applied to space. ring 20 during the drilling operation.
    [0022] Other sensor types can be used if desired. For example, it is not necessary for the flowmeter 58 to be a Coriolis flowmeter, as a turbine flowmeter, an acoustic flowmeter, or another type of flowmeter could be used instead. from that.
    [0023] In addition, the drill string 16 can include its own sensors 60, eg for direct measurement of downhole pressure. These sensors 60 may be of the type known to those skilled in the art as pressure during drilling (PWD), measurement during drilling (MWD) and/or profiling during drilling (LWD). These drill string sensor systems generally provide at least pressure measurement, and can also provide temperature measurement, detection of drill string characteristics (such as vibration, weight on bit, grip-slip, etc.), characteristics of the drill string. formation (such as resistivity, specific gravity, etc.) and/or other measurements. Various forms of wired or wireless telemetry (acoustic, pressure pulse, electromagnetic, etc.) can be used to transmit sensor measurements down the well to the surface.
    [0024] Additional sensors could be included in system 10 if desired. For example, another flow meter 67 could be used for measuring the flow of fluid 18 leaving wellhead 24, another Coriolis flow meter (not shown) could be interconnected directly upstream or downstream of a pump. of drill slurry 68, etc.
    [0025] Fewer sensors could be included in system 10 if desired. For example, the output of the rig mud pump 68 could be determined by counting pump strokes, rather than by using flow meter 62 or any other flow meters.
    [0026] Note that separator 48 could be one. 3- or 4-stage separator, or a gas and mud separator (sometimes referred to as an "improvised degasser"). However, separator 48 is not necessarily used in system 10.
    [0027] Drilling fluid 18 is pumped through cane tube line 26 and into drill string 16 by rig mud pump 68. Pump 68 receives fluid 18 from mud well 52 and the flows through a cane tube manifold 70 to cane tube 26. Fluid 18 then flows down through drill string 16, up through annular space 20, through slurry return lines 30, 73, through the pressure regulator manifold 32, and then through separator 48 and vibrating screen 50 to mud pit 52 for conditioning and recirculation.
    [0028] Note that, in system 10 as described so far above, the pressure regulator 34 cannot be used to control the back pressure applied to the annular space 20 to control the pressure well below, unless the fluid 18 is flowing through the pressure regulator. In conventional superbalanced drilling operations, a lack of fluid flow 18 will occur, for example, whenever a connection is made to drill string 16 (for example, for adding another length of drill pipe to the drill string, as well hole 12 is drilled deeper), and the lack of circulation will require that the pressure below the well is regulated solely by the specific weight of fluid 18.
    [0029] In system 10, however, fluid flow through pressure regulator 34 can be maintained, although fluid does not circulate through drill string 16 and annular space 20 while a connection is being made to the drill string . Thus, pressure can still be applied to annular space 20 by restricting the flow of fluid 18 through pressure regulator 34, although a separate back pressure pump may not be used.
    [0030] When fluid 18 is not circulating through drill string 16 and annular space 20 (for example, when a connection is made in the drill string), fluid is fluid from pump 68 to the regulator manifold of pressure 32 through a bypass line 72, 75. Thus, fluid 18 can bypass the cane tube line 26, drill string 16 and annular space 20, and can flow directly from the pump probe mud 68 to the mud return line 30, which remains in communication with the annular space 20. A restriction of this flow by the pressure regulator 34 in this way will cause pressure to be applied to the annular space 20 (e.g. in a typical pressure managed perforation).
    [0031] As described in Figure 1, both the by-pass line 75 and the slurry return line 30 are in communication with the annular space 20 through a single line 73. However, the by-pass line 75 and the slurry return line 30 could instead be separately connected to the wellhead 24, eg using an additional side valve (eg below the RCD 22), in which case each of the lines 30, 75 would be directly in communication with the annular space 20.
    [0032] Although this might require some additional piping at the rig site, the effect of the annular space pressure would be essentially the same as that connecting bypass line 75 and slurry return line 30 to common line 73. , it should be appreciated that several different configurations of the components of the system 10 can be used, and still remain within the scope of this exposition.
    [0033] Fluid flow 18 through bypass line 72, 75 is regulated by a pressure regulator or other type of flow control device 74. Line 72 is upstream of bypass flow control device 74, and line 75 is downstream of the bypass flow control device.
    [0034] The flow of fluid 18 through the cane tube line 26 is substantially controlled by a valve or other type of flow control device 76. Since the flow of fluid 18 through each of the cane tube lines and of by-pass 26, 72 is useful in the inlet traffic density of how wellbore pressure is affected by these flows, the flow meters 64, 66 are depicted in Figure 1 as being interconnected in these lines.
    [0035] However, the flow rate through the cane tube line 26 could be determined, even if only the flow meters 62, 64 were used, and the flow rate through the bypass line 72 could be determined, even if only the flow meters 62, 66 were used. Thus, it should be understood that it is not necessary for the system 10 to include all of the sensors shown in Figure 1 and described here, and the system could instead include additional sensors, different combinations and/or types of sensors, etc.
    [0036] In the example of Figure 1, a bypass flow control device 78 and a flow restriction 80 can be used to fill the cane tube line 26 and the drill string 16, after a connection is made at the drill string, and for equalizing the pressure between the cane tube line and the return lines 30, 73, before opening the flow control device 76. Otherwise, a sudden opening of the flow control device 76, before the cane line 26 and drill string 16 are filled and pressurized with fluid 18 could cause an undesirable pressure transient in the annular space 20 (e.g., due to the flow to the pressure regulator manifold 32 temporarily being lost when filling the cane line and drill string with fluid, etc.).
    [0037] By opening the cane tube by-pass flow control device 78 after a connection is made, the fluid 18 is allowed to fill the cane tube line 26 and the drill string 16 as a substantial part of the fluid continues to flow through bypass line 72, thereby allowing for a continued controlled application of pressure to annular space 20. After the pressure in the cane tube line 26 has equalized with the pressure in the slurry return lines 30 , 73 and on bypass line 75, flow control device 76 can be opened and then flow control device 74 can be closed to slowly divert a greater proportion of fluid 18 from the bypass line. by-pass 72 to the cane tube line 26.
    [0038] Before a connection is made to drill string 16, a similar process can be carried out, except in reverse, to gradually divert fluid flow 18 from cane tube line 26 to bypass line 72 in. a preparation for adding more drill pipe to drill string 16. That is, the flow control device 74 can be gradually opened to slowly divert a greater proportion of the fluid 18 from the cane tube line 26 to the line by-pass 72, and then the flow control device 76 can be closed.
    [0039] Note that bypass flow control device 78 and flow restriction 80 could be integrated into a single element (for example, a flow control device having a flow restriction there), and the devices flow control devices 76, 78 could be integrated into a single flow control device 81 (eg a single pressure regulator, which would gradually open to slowly fill and pressurize the cane line 26 and drill string 16 after a drill pipe connection is made, and then fully open to allow maximum flow during drilling).
    [0040] However, typical conventional drilling rigs are equipped with the flow control device 76 in the form of a valve in the cane tube manifold 70, and the use of the cane tube valve is incorporated into usual drilling practices, the individually operable flow control devices 76, 78 preserve the use of flow control device 76. Flow control devices 76, 78 are sometimes collectively referred to below as if they were the single flow control device 81, but it is to be understood that the flow control device 81 may include the individual flow control devices 76, 78.
    [0041] Another example is illustrated representatively in Figure 2. In this example, the flow control device 76 is connected upstream of the probe cane tube manifold 70. This arrangement has certain benefits, such as no modification being necessary in the tube cane 70 tube manifold or in the line between the manifold and kelly, the tube cane 82 bleed valve can be used to vent the tube cane 26 as in normal drilling operations (no need to change by staff probe), etc.
    [0042] The flow control device 76 can be interconnected between the probe pump 68 and the cane tube manifold 70 using, for example, quick couplings 84 (such as hammer couplings, etc.). This will allow the flow control device 76 to be conveniently adapted for interconnection in various probe pump lines.
    [0043] A specially adapted fully automated flow control device 76 (e.g. automatically controlled by the controller 96 depicted in figure 3) can be used to control the flow through the cane tube line 26, instead of using the valve of conventional cane tube in a 70 probe cane tube manifold. The entire flow control device 81 can be customized for use as described here (eg for flow control through the cane tube line 26 in conjunction with a bypass of fluid 18 between the cane tube line and the bypass line 72 to thereby control the pressure in the annular space 20, etc.), rather than for conventional drilling purposes.
    [0044] In the example of Figure 2, a remotely controllable valve or other flow control device 160 is optionally used to divert fluid flow 18 from the cane tube line 26 to the mud return line 30 downstream of the pressure regulator manifold 32 so as to transmit signals, data, commands, etc. to downhole tools below (such as the downhole assembly of figure 1 including sensors 60, other equipment including mud motors , deflection devices, steering controls, etc.). Device 160 is controlled by a telemetry controller 162 which can encode information such as a sequence of flow deviations detectable by downhole tools (e.g. some decrease in flow through a downhole tool will result from of a corresponding diversion of flow by the device 160 from the cane tube line 26 to the slurry return line 30).
    [0045] A suitable telemetry controller and a suitable remotely operable flow control device are provided in a GEO-SPAN™ system marketed by Halliburton Energy Services, Inc. of Houston, Texas, USA Telemetry controller 162 can be connected to an INSITE™ system or other acquisition and control interface 94 on control system 90. However, other types of telemetry controllers and flow control devices may be used while remaining within the scope of this disclosure.
    [0046] Note that each of the flow control devices 74, 76, 78 and pressure regulators 34 preferably is remotely and automatically controllable to maintain a desired downhole pressure by maintaining a desired storage address pressure at or near the surface. However, any one or more of these flow control devices 74, 76, 78 and pressure regulators 34 could be manually controlled, while remaining within the scope of this disclosure.
    [0047] A pressure and flow control system 90, which can be used in conjunction with system 10 and the associated methods of figures 1 and 2, is representatively illustrated in figure 3. The control system 90 of preference is fully automated, although some human intervention can be used, for example, to safeguard against improper operation, start certain routines, update parameters, etc.
    [0048] The control system 90 includes a hydraulic model 92, a data acquisition and control interface 94 and a controller 96 (such as a programmable logic controller or PLC, a properly programmed computer, etc.). Although these elements 92, 94, 96 are described separately in Figure 3, any or all of them could be combined into a single element, or the functions of the elements could be separated into additional elements, other additional elements and/or functions could be provided. , etc.
    [0049] The hydraulic model 92 is used in the control system 90 for determining the desired annular space pressure at or near the surface to obtain a desired downhole pressure. Data such as well geometry, fluid properties and well drift information (such as geothermal gradient and pore pressure gradient, etc.) are used by hydraulic model 92 in making this determination, as well as real-time sensor data acquired by the data acquisition and control interface 94.
    [0050] Thus, there is a continuous two-way transfer of data and information between the hydraulic model 92 and the data acquisition and control interface 94. It is important to appreciate that the data acquisition and control interface 94 operates to maintain a substantially constant flow of real-time data from sensors 44, 54, 66, 62, 64, 60, 58, 46, 36, 38, 40, 56, 67 to hydraulic model 92, so that hydraulic model has the information it needs to adapt to changing circumstances and to update the desired annular space pressure, and the hydraulic model operates to supply the data acquisition and control interface substantially continuously with a value for the desired space pressure cancel.
    [0051] A suitable hydraulic model for use as hydraulic model 92 in control system 90 is REAL TIME HYDRAULICS™ or GB SETPOINT™ marketed by Halliburton Energy Services, Inc. of Houston, Texas, USA Another suitable hydraulic model is provided. under the trade name IRIS™ and yet another one is available from SINTEF of Trondheim, Norway. Any suitable hydraulic model can be used on sensor 90, in keeping with the principles of this exposition.
    [0052] A suitable data acquisition and control interface for use in the data acquisition and control interface on control system 90 are SENTRY™ and INSITE™ marketed by Halliburton Energy Services, Inc. Any suitable data acquisition and control interface can be used in control system 90, keeping to the principles of this exhibition.
    [0053] The controller 96 operates to maintain a desired set point annular space pressure by controlling the operation of the slurry back pressure regulator 34 and other devices. When an updated desired annular space pressure is transmitted from the data acquisition and control interface 94 to controller 96, the controller uses the desired annular space pressure as a set point and controls the pressure regulator's operating environment 34 in a way (e.g., increasing or decreasing a resistance to flow through the pressure regulator, as needed) to maintain the set point pressure in the annular space 20. The pressure regulator 34 can be closed further to increase the resistance to flow, or open more to decrease resistance to flow.
    [0054] Maintaining the set point pressure is performed by comparing the set point pressure with a measured annular space pressure (such as the pressure detected by any of the sensors 36, 38, 40) and decreasing a resistance to flow through the pressure regulator 34 if the measured pressure is greater than the set point pressure, and increasing the resistance to flow through the pressure regulator if the measured pressure is less than the set point pressure. set point. Obviously, if the set point and metered pressures are the same, then no adjustment of the pressure regulator 34 will be required. This process is preferably automated so that no human intervention is required, although human intervention can be used if desired.
    [0055] Controller 96 can also be used to control the operation of cane tube flow control devices 76, 78 and bypass flow control device 74. Controller 96 can thus be used for automation of the fluid flow diversion processes 18 from the cane tube line 26 to the bypass line 72, before making a connection to the drill string 16, then diverting the flow from the bypass line to the cane tube line, after the connection is made, and then resumption of normal fluid circulation 18 for drilling. Again, no human intervention can be required in these automated processes, although human intervention can be used if desired, eg for initiating each process in turn, for manual operation of a system component, etc.
    [0056] Data validation and prediction techniques can be used in system 90 to protect against erroneous data being used, to ensure that the determined values are aligned with the predicted values, etc. Suitable validation and prediction techniques are described in International Application No. PCT/US11/59743, although other techniques may be used if desired.
    [0057] When drilling in an open circulation system, pressure measurement tools during drilling (PWD) have been used for monitoring downhole pressures, and have been used for event detection of well hole. With pressure managed drilling (MPD) and the use of pressure regulators 34 and other types of flow control devices to maintain the desired wellbore pressure, the use of PWD measurements for event detection was greatly limited .
    [0058] A CF calibration factor for adjusting a fluid friction pressure calculated by hydraulic model 92 can be given by the following equation:. CF = (PWD psi (6.89 kPa) - WHP - Hydrostatic) / model friction (1)
    [0059] where PWD psi (6.89 kPa) is the pressure measurement made by a PWD tool (such as sensor 60) interconnected in drill string 16, WHP is the annular space pressure as measured at or near the surface (eg at wellhead 24), and Hydrostatic is the static wellbore pressure (eg without a circulation through the drill string and annular space 20) at a location in the wellbore, due to weight of a column of fluid 18 above the location. Hydrostatics is calculated based on a measured fluid specific gravity 18 and a measured true vertical depth of the fluid column above the wellbore location.
    [0060] Model friction is calculated in real time by hydraulic model 92. Calibration factor CF is applied to model friction (CF * model friction) for the calculation of actual friction pressure (Friction).
    [0061] The numerator of the above equation (PWD psi - WHP - Hydrostatic) under normal pressure managed drilling conditions is a determination of the friction pressure measured in wellbore 12, and is a real-time value (each of the terms in the numerator is available for use in the real-time equation). A transmission frequency of PWD data can be from several seconds to several minutes, and Equation (1) can be applied to calculate the CF calibration factor each time PWD data is received.
    [0062] Under normal circumstances, there should be very little difference between the modeled and measured friction pressure (the denominator and numerator, respectively, in the above equation), so that CF is approximately 1. If CF increases, this will be a indicator that fluid friction in wellbore 12 is increasing (eg, more cuts in wellbore, partial collapse of wellbore, etc.). If CF starts to decrease, this will be an indication of decreased fluid friction, which could be the result of a gas rise (for example, a gas expanding in annular space 20 as it flows upward to the surface, thereby reducing the effective specific weight of the annular space fluid column 18) .
    [0063] In a pressure managed drilling (for example, a drilling with the storage address closed to atmosphere at or near the surface, and with the pressure in the annular space 20 being regulated to thereby regulate the pressure below the well) , one or more pressure regulators 34, which restrict the flow of fluid 18 from the annular space, may be controlled using the following equation: WHP = Desired - Friction - Hydrostatic (2)
    [0064] where Desired is the desired pressure at any location in a wellbore (for example, at a bottom or distal end of the wellbore, in a casing nozzle, in an underpressurized zone penetrated by the wellbore, etc.), and Friction is the pressure due to fluid friction in the annular space 20 (Friction = CF * pattern friction as discussed above).
    [0065] The pressure regulator(s) 34 may be opened more (resulting in less restriction to flow) if the WHP is greater than that given by the equation above, and the pressure regulator(s) may be closed more (resulting in more flow restriction) if the WHP is less than that given by the equation above. The use of appropriate values for the terms in Equation (2) for calculating the WHP is therefore very important for controlling the operation of the pressure regulator(s) 34 or otherwise precisely controlling the bore pressure of well 12.
    [0066] It has been found that after an inflow occurs in a situation where a PWD tool or other pressure sensor 60 is part of the drill string 16, the hydraulic model 92 will adjust the CF (for example, applying the Equation (1) above) to maintain a desired wellbore pressure (see the logging example depicted in figure 4). When the control system 90 is controlling the pressure of wellbore 12 with automation (for example, the pressure regulator(s) 34 is (are) automatically controlled to maintain the desired wellbore pressure ) and with hydraulic model 92 operating, the CF can rapidly decrease (eg as low as 0.001) when such an inflow occurs.
    [0067] A low CF like this is not correct, as with any fluid circulating 18 there will have to be friction in wellbore 12. The error in Equation 1 during an inflow, then, is in the Hydrostatic term (for example , in the specific gravity of static fluid used to calculate the hydrostatic pressure). During an inflow, as the gas migrates upward in the annular space 20, and the inflow fluid (eg gas condensate, etc.) transitions from a single phase to a multiphase fluid, the hydrostatic pressure in the space cancel 20 will decrease.
    [0068] To use PWD for header detection and prevention in MPD operations, a header identification (inflow) could be through real-time monitoring, trend analysis applications, and/or neural network analysis, etc. of the calculated calibration factor CF of hydraulic model 92. Other techniques for identifying the inflow from the characteristics of the CF (eg evaluation of a slope, second order derivative, etc. of the CF) could be used if desired . During the CF real-time analysis, if at any point a predetermined regression or aggression occurred, an alarm could be activated, and the hydraulic model 92 could start to correct the Hydrostatics term of the control algorithm to avoid any flow of additional entry.
    [0069] What follows is an algorithm which, applied as discussed more fully below, will prevent the input flow from increasing: Adjusted MW = Previous MW - ((Previous Friction - Observed Friction)/(0.052 * TVD)) (3)
    [0070] where Adjusted MW is an adjusted slurry weight (fluid specific gravity 18) for use in calculating the Hydrostatic term, Prior MW is a previously calculated or measured fluid specific gravity, Prior Friction is the previous modeled friction pressure next , Observed Friction is a currently calculated friction pressure (for example, using Equation 2) , and TVD is a true vertical depth. Note that the term 0.052 is for converting slurry weight in pounds per gallon to pounds per square inch (when multiplied by TVD in feet). Conversion factor time stamp will change if other units are used.
    [0071] Applied repeatedly, this Equation 3 will adjust the Hydrostatic term until the CF substantially equals 1. Once the inflow is outside the annular space 20, the CF will begin to increase and, using the same equation, the Hydrostatic term will be adjusted accordingly.
    [0072] Once the input stream has been identified (for example, using real-time monitoring, trend analysis applications, neural network analysis, etc.), Equation 3 can be repeatedly applied to taper off the Hydrostatic term of Equation 1. In actual practice, this will result in a gradual decrease in the Hydrostatic term of Equation 1, until the CF term stabilizes and starts to increase again.
    [0073] In the example profile of Figure 4, the calibration factor CF decreases to near zero when an inflow to a wellbore occurs. Note that the decrease in CF starts before a significant increase in well volume, and before an increase in the 3P gas reading. This (the inflow and the resulting decrease in CF) is a situation which can be avoided using the principles described here.
    [0074] Note that the MW mud weight remains unmodified in the profile of Figure 4, even after the inflow has occurred, the well volume has increased and an increased gas has been detected on the surface. This lack of adjustment in fluid density after the inflow, with the consequent reduction in the CF calibration factor, is mitigated by using the principles described here.
    [0075] Since the decrease in the CF calibration factor described in the profile of figure 4 precedes the increase in well volume and the increased gas reading on the surface, it will be appreciated that this decrease in CF can serve as an early indicator of the occurrence input stream. Using real-time monitoring, trend analysis applications, neural network analysis techniques, etc. mentioned above, this input stream indicating CF decreases can be readily identified so that an operator can be alerted, corrective actions (such as using Equation 3 above to modify the term Hydrostatics, etc.) can be taken, and additional inflows may be impeded.
    [0076] This approach to early detection of heading (inflow) and prevention is markedly different from previous approaches. An MPD header detection has generally been by monitoring pressure regulator setting and mass flow differences (mass flow out of the well minus mass flow into the well), whose techniques have so far produced mixed results.
    [0077] When measurements are made by a PWD tool (or other well pressure measuring device below, such as an MWD tool) are used in the manner described above, the CF calibration factor can be accurately determined, even if an inflow results in a change in fluid density. This will allow for improved wellbore pressure control, with the pressure measurement tool (PWD, MWD, etc.) in wellbore 12.
    [0078] Referring now in addition to Figure 5, an example flowchart for a method 100 of detecting and mitigating an inflow to a wellbore 12 during drilling is illustrated representatively. Method 100 can be used with the well drilling system 10 and the pressure and flow control system 90 described above, or the method can be used with other systems.
    [0079] In step 102, the CF calibration factor is determined. Equation 1 can be used to calculate the calibration factor CF, based on measured wellbore pressure 12 (eg from sensors 60, such as PWD or MWD tools), measured annular space pressure 20 at or near the surface (WHP), hydrostatic pressure calculated from measured fluid specific gravity and true vertical depth, and a friction pressure from hydraulic model 92. A further description of the CF calibration factor is provided in US Patent No. 8240398, assigned to the assignee of this application.
    [0080] The CF calibration factor is used in step 104 to calculate an actual friction pressure. The actual friction pressure (Friction) is used to calculate a desired annular space pressure 20 at or near the surface (WHP) which will result in a desired pressure at a location in wellbore 12. Equation 2 can be used for this purpose.
    [0081] In step 106, the calibration factor CF determined in step 102 is evaluated. As discussed above, a relatively high value for CF is indicative of increased fluid friction in the annular space 20, for example, due to increased drill cuts, partial wellbore collapse, etc. A rapid decrease in CF is indicative of an inflow to the wellbore. Techniques known to those skilled in the art, such as trend analysis, a neural network, a slope analysis and/or second order derivatives, etc. can be used in step 106 to identify when an input stream or other type of event is occurring, or has occurred.
    [0082] In step 108, a specific gravity of the fluid 18 is adjusted so as to mitigate the effects of an event indicated in step 106. For example, if an inflow is indicated in step 106, then, in step 108, the fluid specific gravity 18 (eg slurry weight MW) may be decreased in increments, so that the calculated Hydrostatic term used in Equation 2 is also decreased. Equation 3 can be used for this purpose. The decrease in fluid specific gravity 18 corresponds to a decreased specific gravity in the annular space 20, due to inflow, a gas expansion, etc.
    [0083] Note that the actual specific gravity of fluid 18 is not decreased. Instead, the term Hydrostatic used in Equation 2 is decreased in increments by decreasing the slurry weight MW used in calculating the hydrostatic pressure, so that the applied pressure (WH in Equation 3) increases in increments.
    [0084] This increased applied pressure WHP will eventually avoid additional inflows to wellbore 12, at which point the CF calibration factor will begin to increase and, as a result of a repeated application of steps 102, 104 and 108, the weight MW fluid used to calculate the Hydrostatic term in Equation 2 will increase. Eventually, the CF calibration factor should level off by approximately one as conditions return to normal.
    [0085] It may be desired to limit the applied increased WHP, so as to avoid, for example, damage to a fragile or sensitive formation. In this case, the Hydrostatics term in Equation 2 can be decreased only by a predetermined amount, and/or a predetermined maximum level can be set for the applied WHP so that a pressure in wellbore 12 at a certain location does not exceed the a maximum level. A limit on the applied WHP can also be regulated (or alternatively) to prevent damage to equipment (such as surface pressure control and flow equipment).
    [0086] Whether the evaluation of the CF calibration factor in step 106 (for example, by trend analysis, a neural network, a slope analysis and/or second order derivatives, etc.) indicates that a substantial input stream has entered at wellbore 12, and well control procedures are to begin, fluid 18 may be automatically diverted to the rig control equipment. For example, in the schematic in Figure 2, fluid flow 18 can be diverted from pressure regulator manifold 32 to a probe pressure regulator manifold (eg, through the pressure regulator line).
    [0087] In response to an increase in the CF calibration factor (eg, indicating increased drill cuts, partial wellbore collapse, etc.), the Hydrostatic term in Equation 2 could be increased by increments instead. This will result in less pressure being applied to the wellbore 12 at or near the surface, if desired, for example to compensate for the increased volume of drill cuts in the annular space 20, etc. The Hydrostatic term can be increased in increments until the CF calibration factor starts to decrease.
    [0088] It can now be fully appreciated that the above exposition provides significant advances to the wellbore pressure control technique. In an example described above, a calibration factor CF is used to calculate the fluid friction pressure in a 12 wellbore, and a decrease in the calibration factor indicates that an inflow has occurred. A fluid density term 18 may be changed in increments in response to detecting a predetermined change in calibration factor CF, in order, for example, to mitigate the effects of an inflow.
    [0089] A wellbore drilling method is provided for the technique by the above disclosure. In one example, the method may comprise: drilling a wellbore 12, a fluid 18 circulating through the wellbore 12 during drilling; determining a calibration factor CF which is applied to a modeled fluid friction pressure; and control of drilling based, at least in part, on a change in the CF calibration factor.
    [0090] The modeled fluid friction pressure can be generated by a hydraulic model 92.
    [0091] An increase in the CF calibration factor may indicate an increase in actual fluid friction in the wellbore 12. A decrease in the CF calibration factor may indicate a decrease in the hydrostatic pressure in the wellbore.
    [0092] The method may include setting an alarm when the CF calibration factor decreases below a predetermined level, and/or when the CF calibration factor decreases at a rate greater than the predetermined.
    [0093] The control step may include automatically diverting fluid flow 18 to a probe pressure regulator manifold in response to a change in the CF calibration factor.
    [0094] The control step may include a pressure increase applied to wellbore 12 at or near the ground surface, in response to the change in the CF calibration factor. The pressure increase step may include an increase in pressure applied to the wellbore to a predetermined maximum level.
    [0095] The control step can include the incrementing decrease of a Hydrostatic term in the equation: WHP = Target - Friction - Hydrostatic, where WHP is the pressure applied to the wellbore at or near the ground surface, Target is a desired pressure at a wellbore location, Friction is fluid friction in the wellbore, and Hydrostatic is the hydrostatic pressure at the location.
    [0096] The step-down step may include step-down of the Hydrostatic term in response to a decrease in the CF calibration factor.
    [0097] The step-down step may include step-down of the Hydrostatic term, until the CF calibration factor begins to increase, until the WHP term reaches a predetermined maximum level, and/or until the Hydrostatic term has been decreased by a predetermined amount.
    [0098] The control step may include, in response to an increase in the CF calibration factor, the incremental increase of a Hydrostatic term in the equation: WHP = Desired - Friction - Hydrostatic, where WHP is the pressure applied to the hole of well at or near the ground surface, Target is a desired pressure at a wellbore location, Friction is a fluid friction in the wellbore, and Hydrostatic is the hydrostatic pressure at the location. The Hydrostatic term can be increased in increments until the CF calibration factor decreases.
    [0099] A 10 well drilling system is also described above. In one example, the system 10 may comprise a hydraulic model 92 which determines a modeled fluid friction pressure and a calibration factor CF applied to the modeled friction pressure; and a flow control device (such as pressure regulator 34) which is automatically controlled in response to a change in calibration factor CF.
    [0100] Although several examples have been described above, with each example having certain features, it should be understood that it is not necessary for a particular feature of an example to be used exclusively with that example. Rather, any of the features described above and/or set forth in the drawings may be combined with any of the examples, in addition to or in place of any of the other features in those examples. Features in one example are not mutually exclusive to features in another example. Instead, the scope of this exhibit encompasses any combination of any of the features.
    [0101] Although each example described above includes a certain combination of features, it should be understood that it is not necessary for all features of an example to be used. Instead, any of the features described above can be used, without any other particular features or features also being used.
    [0102] It should be understood that the various modalities described here can be used in various orientations, such as tilted, inverted, horizontal, vertical, etc. and in various configurations, without deviating from the principles of this exposition. The modalities are merely described as examples of useful applications of the exhibition principles, which are not limited to any specific details of these modalities.
    [0103] In the above description of representative examples, directional terms (such as "above", "below", "upper", "lower", etc.) are used for convenience with reference to the associated drawings. However, it should be clearly understood that the scope of this exposition is not limited to any directions described here.
    [0104] The terms "including", "includes", "comprising", "comprises" and similar terms are used in a non-limiting sense in this specification. For example, if a system, method, apparatus, device, etc. is described as "including" a certain feature or element, the system, method, apparatus, device, etc. may include that feature or element, and may also include other features or elements. Similarly, the term "comprises" is taken to mean "comprises, but is not limited to".
    [0105] Obviously, a person skilled in the art, upon careful consideration of the above description of representative exhibit modalities, will readily appreciate that many modifications, additions, substitutions, deletions, and other changes can be made to the specific modalities, and such changes are contemplated by the principles of this exhibition. For example, structures shown as being separately formed in other examples may be integrally formed and vice versa. Therefore, the foregoing detailed description is to be clearly understood to be given by way of illustration and example only, the spirit and scope of the invention being limited solely by the appended claims and their equivalents.
    权利要求:
    Claims (8)
    [0001]
    1. Method of well drilling, characterized in that it comprises: drilling a wellhole (12), a fluid (18) circulating through the wellbore during drilling; the determination of a calibration factor (CF), which is applied to a modeled fluid friction pressure; and drilling control, by controlling the wellbore pressure, based at least in part on a change in the calibration factor, where: an increase in the calibration factor indicates an increase in actual fluid friction in the wellbore ; and/or a decrease in calibration factor indicates a decrease in hydrostatic pressure in the wellbore.
    [0002]
    2. Method according to claim 1, characterized in that the fluid friction pressure modeled is generated by a hydraulic model.
    [0003]
    3. Method according to claim 1 or 2, characterized in that the control further comprises automatically diverting the fluid flow to a probe throttling collector in response to the change in calibration factor.
    [0004]
    4. Method according to any one of claims 1 to 3, characterized in that it further comprises one of the setting of an alarm when the calibration factor decreases below a predetermined level or the setting of an alarm when the calibration factor decrease at a rate greater than a predetermined rate.
    [0005]
    5. Method according to any one of claims 1 to 4, characterized in that the control further comprises increasing the pressure applied to the wellbore at or near the ground surface, in response to the change in the calibration factor, optionally to a predetermined maximum level.
    [0006]
    6. Method according to any one of claims 1 to 4, characterized in that the control further comprises the decrease in increments of a hydrostatic term in the equation: WHP = Desired - Friction - Hydrostatic, where WHP is the pressure applied to the hole pressure at or near the ground surface, Target is a desired pressure at a wellbore location, Friction is a fluid friction at the wellbore, and Hydrostatic is a hydrostatic pressure at the location.
    [0007]
    7. Method according to claim 6, characterized in that the reduction in increments further comprises the decrease in increments of the hydrostatic term: in response to a decrease in the calibration factor; or until the calibration factor starts to increase; or until the WHP term reaches a predetermined maximum level; or until the hydrostatic term has decreased by a predetermined amount.
    [0008]
    8. Method according to any one of claims 1 to 5, characterized in that the control further comprises, in response to an increase in the calibration factor, the increase in increments of a hydrostatic term in the equation: WHP = Desired - Friction - Hydrostatic, where WHP is the pressure applied to the wellbore at or near the ground surface, Desired is a desired pressure at a wellbore location, Friction is a fluid friction in the wellbore, and Hydrostatic is a pressure hydrostatic in location.
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    同族专利:
    公开号 | 公开日
    BR112014013215A2|2017-06-13|
    RU2592583C2|2016-07-27|
    US20130133948A1|2013-05-30|
    WO2013081775A1|2013-06-06|
    EP2785971A1|2014-10-08|
    CA2852710C|2016-10-11|
    AU2012346426B2|2015-07-16|
    MY171268A|2019-10-07|
    US9725974B2|2017-08-08|
    EP2785971A4|2016-05-11|
    MX2014006013A|2014-06-04|
    RU2014125521A|2016-01-27|
    AU2012346426A1|2014-07-17|
    EP2785971B1|2018-10-10|
    CA2852710A1|2013-06-06|
    CN103958830A|2014-07-30|
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    法律状态:
    2018-12-04| B06F| Objections, documents and/or translations needed after an examination request according [chapter 6.6 patent gazette]|
    2019-12-31| B06U| Preliminary requirement: requests with searches performed by other patent offices: procedure suspended [chapter 6.21 patent gazette]|
    2021-03-30| B09A| Decision: intention to grant [chapter 9.1 patent gazette]|
    2021-05-04| B16A| Patent or certificate of addition of invention granted [chapter 16.1 patent gazette]|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 05/11/2012, OBSERVADAS AS CONDICOES LEGAIS. |
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