EP2732130B1

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Info

Publication number: EP2732130B1
Application number: EP11869316.7A
Authority: EP
Inventors: Stuart M. JEFFRIES
Original assignee: Halliburton Energy Services Inc
Current assignee: Halliburton Energy Services Inc
Priority date: 2011-07-12
Filing date: 2011-07-12
Publication date: 2018-05-02
Anticipated expiration: 2031-07-12
Also published as: BR112014000553B1; EP2732130A4; CA2841125A1; BR112014000553A2; CA2841125C; EP2732130A1; RU2014104013A; RU2585780C2; MX353095B; CN103688020A; WO2013009305A1; BR112014000553B8; MX2014000417A

Description

TECHNICAL FIELD

The present disclosure relates generally to equipment utilized and operations performed in conjunction with well drilling operations and, in an embodiment described herein, more particularly provides for formation testing in managed pressure drilling.

BACKGROUND

Managed pressure drilling is well known as the art of precisely controlling bottom hole pressure during drilling by utilizing a closed annulus and a means for regulating pressure in the annulus, an example can be found in the documentGB 2 156 403 A which is considered the closest prior art. The annulus is typically closed during drilling through use of a rotating control device (RCD, also known as a rotating control head or rotating blowout preventer) which seals about the drill pipe as it rotates.
It will, therefore, be appreciated that it would be beneficial to be able to perform formation testing during managed pressure drilling operations.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a representative view of a well drilling system and method which can embody principles of the present disclosure.
FIG. 2 is a representative block diagram of a pressure and flow control system which may be used in the well drilling system and method.
FIG. 3 is a representative flowchart for a method of testing a formation, which method can embody principles of this disclosure.
FIG. 4 is a representative flowchart for another version of the formation testing method.

DETAILED DESCRIPTION

Representatively illustrated inFIG. 1 is a welldrilling system 10 and associated method which can embody principles of the present disclosure. In thesystem 10, awellbore 12 is drilled by rotating adrill bit 14 on an end of adrill string 16. Drillingfluid 18, commonly known as mud, is circulated downward through thedrill string 16, out thedrill bit 14 and upward through an annulus 20 formed between the drill string and thewellbore 12, in order to cool the drill bit, lubricate the drill string, remove cuttings and provide a measure of bottom hole pressure control. A non-return valve 21 (typically a flapper-type check valve) prevents flow of thedrilling fluid 18 upward through the drill string 16 (e.g., when connections are being made in the drill string).
Control of bottom hole pressure is very important in managed pressure drilling, and in other types of drilling operations. Preferably, the bottom hole pressure is precisely controlled to prevent excessive loss of fluid into anearth formation 82 surrounding thewellbore 12, undesired fracturing of the formation, undesired influx of formation fluids into the wellbore, etc.
In typical managed pressure drilling, it is desired to maintain the bottom hole pressure just slightly greater than a pore pressure of the formation, without exceeding a fracture pressure of the formation. This technique is especially useful in situations where the margin between pore pressure and fracture pressure is relatively small.
In typical underbalanced drilling, it is desired to maintain the bottom hole pressure somewhat less than the pore pressure, thereby obtaining a controlled influx of fluid from the formation.
In conventional overbalanced drilling, it is desired to maintain the bottom hole pressure somewhat greater than the pore pressure, thereby preventing (or at least mitigating) influx of fluid from the formation. The annulus 20 can be open to the atmosphere at the surface during overbalanced drilling, and wellbore pressure is controlled during drilling by adjusting a density of thedrilling fluid 18.
Nitrogen or another gas, or another lighter weight fluid, may be added to thedrilling fluid 18 for pressure control. This technique is useful, for example, in underbalanced drilling operations.
In thesystem 10, additional control over the bottom hole pressure is obtained by closing off the annulus 20 (e.g., isolating it from communication with the atmosphere and enabling the annulus to be pressurized at or near the surface) using a rotating control device 22 (RCD). The RCD 22 seals about thedrill string 16 above awellhead 24. Although not shown inFIG. 1, thedrill string 16 would extend upwardly through theRCD 22 for connection to, for example, a rotary table (not shown), astandpipe line 26, kelley (not shown), a top drive and/or other conventional drilling equipment.
Thedrilling fluid 18 exits thewellhead 24 via awing valve 28 in communication with the annulus 20 below the RCD 22. Thefluid 18 then flows throughmud return lines 30, 73 to achoke manifold 32, which includes redundant chokes 34 (only one of which might be used at a time). Backpressure is applied to the annulus 20 by variably restricting flow of thefluid 18 through the operative one(s) of the redundant choke(s) 34.
The greater the restriction to flow through the operative choke(s) 34, the greater the backpressure applied to the annulus 20. Thus, downhole pressure (e.g., pressure at the bottom of thewellbore 12, pressure at a downhole casing shoe, pressure at a particular formation or zone, etc.) can be conveniently regulated by varying the backpressure applied to the annulus 20. A hydraulics model can be used, as described more fully below, to determine a pressure applied to the annulus 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 annulus at or near the surface (which can be conveniently measured) in order to obtain the desired downhole pressure.
Pressure applied to the annulus 20 can be measured at or near the surface via a variety ofpressure sensors 36, 38, 40, each of which is in communication with the annulus.Pressure sensor 36 senses pressure below theRCD 22, but above a blowout preventer (BOP)stack 42.Pressure sensor 38 senses pressure in the wellhead below theBOP stack 42.Pressure sensor 40 senses pressure in themud return lines 30, 73 upstream of thechoke manifold 32.
Anotherpressure sensor 44 senses pressure in thestandpipe line 26. Yet anotherpressure sensor 46 senses pressure downstream of thechoke manifold 32, but upstream of aseparator 48,shaker 50 andmud pit 52. Additional sensors includetemperature sensors 54, 56, Coriolisflowmeter 58, andflowmeters 62, 64, 66.
Not all of these sensors are necessary. For example, thesystem 10 could include only two of the threeflowmeters 62, 64, 66. However, input from all available sensors is useful to the hydraulics model in determining what the pressure applied to the annulus 20 should be during the drilling operation.
Other sensor types may be used, if desired. For example, it is not necessary for theflowmeter 58 to be a Coriolis flowmeter, since a turbine flowmeter, acoustic flowmeter, or another type of flowmeter could be used instead.
In addition, thedrill string 16 may include itsown sensors 60, for example, to directly measure downhole pressure.Such sensors 60 may be of the type known to those skilled in the art as pressure while drilling (PWD), measurement while drilling (MWD) and/or logging while drilling (LWD). These drill string sensor systems generally provide at least pressure measurement, and may also provide temperature measurement, detection of drill string characteristics (such as vibration, weight on bit, stick-slip, etc.), formation characteristics (such as resistivity, density, etc.) and/or other measurements. Various forms of wired or wireless telemetry (acoustic, pressure pulse, electromagnetic, etc.) may be used to transmit the downhole sensor measurements to the surface. For example, lines (such as, electrical, optical, hydraulic, etc., lines) could be provided in a wall of thedrill string 16 for communicating power, data, commands, pressure, flow, etc.
Additional sensors could be included in thesystem 10, if desired. For example,another flowmeter 67 could be used to measure the rate of flow of thefluid 18 exiting thewellhead 24, another Coriolis flowmeter (not shown) could be interconnected directly upstream or downstream of arig mud pump 68, etc.
Fewer sensors could be included in thesystem 10, if desired. For example, the output of therig mud pump 68 could be determined by counting pump strokes, instead of by using theflowmeter 62 or any other flowmeters.
Note that theseparator 48 could be a 3 or 4 phase separator, or a mud gas separator (sometimes referred to as a "poor boy degasser"). However, theseparator 48 is not necessarily used in thesystem 10.
Thedrilling fluid 18 is pumped through thestandpipe line 26 and into the interior of thedrill string 16 by therig mud pump 68. Thepump 68 receives thefluid 18 from themud pit 52 and flows it via astandpipe manifold 70 to thestandpipe 26. The fluid then circulates downward through thedrill string 16, upward through the annulus 20, through themud return lines 30, 73, through thechoke manifold 32, and then via theseparator 48 and shaker 50 to themud pit 52 for conditioning and recirculation.
Note that, in thesystem 10 as so far described above, thechoke 34 cannot be used to control backpressure applied to the annulus 20 for control of the downhole pressure, unless thefluid 18 is flowing through the choke. In conventional overbalanced drilling operations, a lack offluid 18 flow will occur, for example, whenever a connection is made in the drill string 16 (e.g., to add another length of drill pipe to the drill string as thewellbore 12 is drilled deeper), and the lack of circulation will require that downhole pressure be regulated solely by the density of thefluid 18.
In thesystem 10, however, flow of thefluid 18 through thechoke 34 can be maintained, even though the fluid does not circulate through thedrill string 16 and annulus 20, while a connection is being made in the drill string. Thus, pressure can still be applied to the annulus 20 by restricting flow of thefluid 18 through thechoke 34, even though a separate backpressure pump may not be used. However, in other examples, a backpressure pump (not shown) could be used to supply pressure to the annulus 20 while thefluid 18 does not circulate through thedrill string 16, if desired.
In the example ofFIG. 1, when fluid 18 is not circulating throughdrill string 16 and annulus 20 (e.g., when a connection is made in the drill string), the fluid is flowed from thepump 68 to thechoke manifold 32 via abypass line 72, 75. Thus, the fluid 18 can bypass thestandpipe line 26,drill string 16 and annulus 20, and can flow directly from thepump 68 to themud return line 30, which remains in communication with the annulus 20. Restriction of this flow by thechoke 34 will thereby cause pressure to be applied to the annulus 20 (for example, in typical managed pressure drilling).
As depicted inFIG. 1, both of thebypass line 75 and themud return line 30 are in communication with the annulus 20 via asingle line 73. However, thebypass line 75 and themud return line 30 could instead be separately connected to thewellhead 24, for example, using an additional wing valve (e.g., below the RCD 22), in which case each of thelines 30, 75 would be directly in communication with the annulus 20.
Although this might require some additional piping at the rig site, the effect on the annulus pressure would be essentially the same as connecting thebypass line 75 and themud return line 30 to thecommon line 73. Thus, it should be appreciated that various different configurations of the components of thesystem 10 may be used, without departing from the principles of this disclosure.
Flow of the fluid 18 through thebypass line 72, 75 is regulated by a choke or other type offlow control device 74.Line 72 is upstream of the bypassflow control device 74, andline 75 is downstream of the bypass flow control device.
Flow of the fluid 18 through thestandpipe line 26 is substantially controlled by a valve or other type offlow control device 76. Note that theflow control devices 74, 76 are independently controllable, which provides substantial benefits to thesystem 10, as described more fully below.
Since the rate of flow of the fluid 18 through each of the standpipe andbypass lines 26, 72 is useful in determining how bottom hole pressure is affected by these flows, theflowmeters 64, 66 are depicted inFIG. 1 as being interconnected in these lines. However, the rate of flow through thestandpipe line 26 could be determined even if only theflowmeters 62, 64 were used, and the rate of flow through thebypass line 72 could be determined even if only theflowmeters 62, 66 were used. Thus, it should be understood that it is not necessary for thesystem 10 to include all of the sensors depicted inFIG. 1 and described herein, and the system could instead include additional sensors, different combinations and/or types of sensors, etc.
In another beneficial feature of thesystem 10, a bypassflow control device 78 may be used for filling thestandpipe line 26 anddrill string 16 after a connection is made in the drill string, and for equalizing pressure between the standpipe line andmud return lines 30, 73 prior to opening theflow control device 76. Otherwise, sudden opening of theflow control device 76 prior to thestandpipe line 26 anddrill string 16 being filled and pressurized with the fluid 18 could cause an undesirable pressure transient in the annulus 20 (e.g., due to flow to thechoke manifold 32 temporarily being lost while the standpipe line and drill string fill with fluid, etc.).
By opening the standpipe bypassflow control device 78 after a connection is made, the fluid 18 is permitted to fill thestandpipe line 26 anddrill string 16 while a substantial majority of the fluid continues to flow through thebypass line 72, thereby enabling continued controlled application of pressure to the annulus 20. After the pressure in thestandpipe line 26 has equalized with the pressure in themud return lines 30, 73 andbypass line 75, theflow control device 76 can be opened, and then theflow control device 74 can be closed to slowly divert a greater proportion of the fluid 18 from thebypass line 72 to thestandpipe line 26.
Before a connection is made in thedrill string 16, a similar process can be performed, except in reverse, to gradually divert flow of the fluid 18 from thestandpipe line 26 to thebypass line 72 in preparation for adding more drill pipe to thedrill string 16. That is, theflow control device 74 can be gradually opened to slowly divert a greater proportion of the fluid 18 from thestandpipe line 26 to thebypass line 72, and then theflow control device 76 can be closed.
Note that theflow control devices 76, 78 could be integrated into a single flow control device 81 (e.g., a single choke which can gradually open to slowly fill and pressurize thestandpipe line 26 anddrill string 16 after a drill pipe connection is made, and then open fully to allow maximum flow while drilling). However, since typical conventional drilling rigs are equipped with theflow control device 76 in the form of a valve in thestandpipe manifold 70, and use of the standpipe valve is incorporated into usual drilling practices, the individually operableflow control devices 76, 78 are presently preferred.
A pressure and flowcontrol system 90 which may be used in conjunction with thesystem 10 and associated method ofFIG. 1 is representatively illustrated inFIG. 2. Thecontrol system 90 is preferably fully automated, although some human intervention may be used, for example, to safeguard against improper operation, initiate certain routines, update parameters, etc.
Thecontrol system 90 includes ahydraulics model 92, a data acquisition andcontrol interface 94 and a controller 96 (such as a programmable logic controller or PLC, a suitably programmed computer, etc.). Although theseelements 92, 94, 96 are depicted separately inFIG. 2, 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.
Thehydraulics model 92 is used in thecontrol system 90 to determine the desired annulus pressure at or near the surface to achieve the desired downhole pressure. Data such as well geometry, fluid properties and offset well information (such as geothermal gradient and pore pressure gradient, etc.) are utilized by thehydraulics model 92 in making this determination, as well as real-time sensor data acquired by the data acquisition andcontrol interface 94.
Thus, there is a continual two-way transfer of data and information between thehydraulics model 92 and the data acquisition andcontrol interface 94. It is important to appreciate that the data acquisition andcontrol interface 94 operates to maintain a substantially continuous flow of real-time data from thesensors 44, 54, 66, 62, 64, 60, 58, 46, 36, 38, 40, 56, 67 to thehydraulics model 92, so that the hydraulics model has the information it needs to adapt to changing circumstances and to update the desired annulus pressure, and the hydraulics model operates to supply the data acquisition and control interface substantially continuously with a value for the desired annulus pressure.
A suitable hydraulics model for use as thehydraulics model 92 in thecontrol system 90 is REAL TIME HYDRAULICS (TM) provided by Halliburton Energy Services, Inc. of Houston, Texas USA. Another suitable hydraulics model is provided under the trade name IRIS (TM), and yet another is available from SINTEF of Trondheim, Norway. Any suitable hydraulics model may be used in thecontrol system 90 in keeping with the principles of this disclosure.
A suitable data acquisition and control interface for use as the data acquisition andcontrol interface 94 in thecontrol system 90 are SENTRY (TM) and INSITE (TM) provided by Halliburton Energy Services, Inc. Any suitable data acquisition and control interface may be used in thecontrol system 90 in keeping with the principles of this disclosure.
Thecontroller 96 operates to maintain a desired setpoint annulus pressure by controlling operation of themud return choke 34. When an updated desired annulus pressure is transmitted from the data acquisition andcontrol interface 94 to thecontroller 96, the controller uses the desired annulus pressure as a setpoint and controls operation of thechoke 34 in a manner (e.g., increasing or decreasing flow resistance through the choke as needed) to maintain the setpoint pressure in the annulus 20. Thechoke 34 can be closed more to increase flow resistance, or opened more to decrease flow resistance.
Maintenance of the setpoint pressure is accomplished by comparing the setpoint pressure to a measured annulus pressure (such as the pressure sensed by any of thesensors 36, 38, 40), and decreasing flow resistance through thechoke 34 if the measured pressure is greater than the setpoint pressure, and increasing flow resistance through the choke if the measured pressure is less than the setpoint pressure. Of course, if the setpoint and measured pressures are the same, then no adjustment of thechoke 34 is required. This process is preferably automated, so that no human intervention is required, although human intervention may be used, if desired.
Thecontroller 96 may also be used to control operation of the standpipeflow control devices 76, 78 and the bypassflow control device 74. Thecontroller 96 can, thus, be used to automate the processes of diverting flow of the fluid 18 from thestandpipe line 26 to thebypass line 72 prior to making a connection in thedrill string 16, then diverting flow from the bypass line to the standpipe line after the connection is made, and then resuming normal circulation of the fluid 18 for drilling. Again, no human intervention may be required in these automated processes, although human intervention may be used if desired, for example, to initiate each process in turn, to manually operate a component of the system, etc.
Referring additionally now toFIG. 4, amethod 100 of testing an earth formation 82 (seeFIG. 1) is representatively illustrated in flowchart form. Themethod 100 may be performed in conjunction with thewell system 10 described above, or it may be performed with other well systems. Thus, themethod 100 is not limited to any of the details of thewell system 10 described herein or depicted in the drawings.
Instep 102, themethod 100 begins while drilling ahead. In thewell system 10,drilling fluid 18 is circulated through thedrill string 16 and annulus 20 while thedrill bit 14 is rotated. It is not necessary for theentire drill string 16 to continuously rotate during drilling, since a drill motor or mud motor (not shown) can be used to impart rotation to the drill bit without rotating the entire drill string.
While drilling ahead, the annulus 20 is sealed from the earth's atmosphere by therotating control device 22. Of course, if thedrill string 16 does not rotate during drilling, then the annulus 20 could be sealed by a device which does not rotate with the drill string.
Instep 104, drilling of theformation 82 is ceased. Thedrill bit 14 is preferably picked up out of contact with theformation 82, so that the drill bit does not cut into the formation. Conditions such as drill string torque, wellbore 12 pressure (e.g., as measured by the downhole sensors 60), annulus 20 pressure at the surface (e.g., as measured bysensors 36, 38, 40), etc., can be measured now for reference purposes.
Instep 106, circulation of the fluid 18 through thedrill string 16 is ceased. Ceasing circulation removes from wellbore pressure the friction pressure due to flow of the fluid 18 through the annulus 20. Therefore, a small reduction in pressure in thewellbore 12 should result from ceasing circulation.
If thesensors 60 are in communication with the surface by, for example, wireless telemetry (e.g., acoustic or electromagnetic telemetry), or wired communication (e.g., via electrical, optical, etc., lines to the surface), then wellbore pressure measurements may be obtained throughout themethod 100. If circulation of the fluid 18 is necessary for communication of measurements from thesensors 60 to the surface, then the measurements can be obtained after circulation is resumed (see step 116).
Instep 108, flow out of the annulus 20 is monitored while, instep 110, thechoke 34 is incrementally opened. As discussed above, while the fluid 18 is circulating through thedrill string 16 and annulus 20, further opening thechoke 34 will result in reducing backpressure applied to the annulus, thereby reducing pressure in thewellbore 12. While the fluid 18 is not circulated, however, incrementally opening thechoke 34 will result in decreasing pressure in thewellbore 12 at a faster rate.
Instep 112, after incrementally opening thechoke 34, flow out of thewellbore 12 is checked to see if the flow is greater than that due to only the reduction in pressure in the wellbore. If not, then thechoke 34 is further incrementally opened (i.e., themethod 100 returns tosteps 108, 110).
If the flow out of thewellbore 12 is greater than would be due to the reduction in pressure in the wellbore (thehydraulics model 92 can determine when this occurs), this is an indication that aninflux 84 of formation fluid from theformation 82 into the wellbore (seeFIG. 1) has occurred. Theinflux 84 will occur when pressure in thewellbore 12 is approximately equal to, or slightly less than, pore pressure in theformation 82. Thus, by detecting when theinflux 84 occurs, and determining what thewellbore 12 pressure is when the influx occurs, theapproximate formation 82 pore pressure can be determined.
Instep 114, the pore pressure is determined. If thesensors 60 are in communication with the surface at the time theinflux 84 is detected, then the pressure in thewellbore 12 can be measured directly in real time. Theformation 82 pore pressure is approximately the same as the pressure in thewellbore 12 when theinflux 84 occurs.
If thesensors 60 are not in communication with the surface at the time theinflux 84 is detected (e.g., if mud pulse telemetry is used to communicate sensor measurements to the surface), then the sensor measurements can be obtained when circulation is resumed instep 116. Alternatively, or in addition, pressure in the annulus 20 at the surface (e.g., as measured bysensors 36, 38, 40) can be added to hydrostatic pressure due to the static column of the fluid 18 in the annulus. This sum is approximately equal to theformation 82 pore pressure.
Instep 116, circulation of the fluid 18 through thedrill string 16 and annulus 20 is resumed.Wellbore 12 pressure measurements can be obtained from thesensors 60 at this point using mud pulse telemetry, in case the sensor measurements were not accessible afterstep 106.
Instep 118, the pore pressure determined instep 114 is verified using measurements from thedownhole sensors 60. The pore pressure may have previously been calculated from surface pressure measurements, density of thedrilling fluid 18, etc. However, any such calculations of pore pressure are preferably verified instep 118 withactual wellbore 12 pressure measurements near theformation 82 using thedownhole sensors 60. Of course, if thedownhole sensors 60 were used for measuring thewellbore 12 pressure and determining the pore pressure, then the verifyingstep 118 may not be performed.
Instep 120, drilling is resumed. Thedrill bit 14 is again rotated, and thedrill string 16 is set down to cut into theformation 82. Since theformation 82 pore pressure has now been measured, pressure in thewellbore 12 can be more accurately controlled relative to the pore pressure to achieve managed pressure drilling objectives (reduced formation damage, reduced fluid loss, etc.). This is far preferable to relying on offset well data for pore pressure gradient to predict pore pressure in theformation 82.
Another version of themethod 100 is representatively illustrated inFIG. 4. In this version, circulation of the fluid 18 through thedrill string 16 and annulus 20 continues while thechoke 34 is incrementally opened and the pore pressure is determined. Thus, steps 106 and 116 of theFIG. 3 version are not used in theFIG. 4 version of themethod 100.
In addition, instead of thestep 108 of monitoring flow out of thewellbore 12 while thechoke 34 is incrementally opened, themethod 100 ofFIG. 4 includes astep 122, in which flow both into and out of the wellbore is monitored. Theflowmeter 66 can be used to monitor flow into thewellbore 12, and theflowmeter 58 can be used to monitor flow out of the wellbore.
Furthermore, instead of thestep 112 of determining whether flow out of thewellbore 12 is greater than that due to reducing pressure via the choke, themethod 100 ofFIG. 4 includes astep 124, in which it is determined whether flow out of the wellbore is greater than flow into the wellbore. If the flow out of thewellbore 12 is greater than flow into the wellbore, this is an indication that theinflux 84 is occurring.
If the flow out of thewellbore 12 is not greater than flow into the wellbore, then theinflux 84 is not occurring, and thechoke 34 is again incrementally opened. These steps are repeated, until theinflux 84 is detected.
Pore pressure in theformation 82 will be approximately equal to, or slightly greater than, pressure in thewellbore 12 when theinflux 84 occurs. Thesensors 60 can be used to measure pressure in thewellbore 12 in real time. Since the fluid 18 continues to flow through thedrill string 16 and annulus 20, mud pulse telemetry can be used, if desired, to transmit pressure and other sensor measurements to the surface.
Alternatively, or in addition, pressure in the annulus 20 at the surface (e.g., as measured bysensors 36, 38, 40) can be added to hydrostatic pressure due to the static column of the fluid 18 in the annulus, and friction pressure due to flow of the fluid through the annulus. This sum is approximately equal to theformation 82 pore pressure.
It can now be fully appreciated that this disclosure provides significant advancements to the art of formation testing. In certain examples described above, aformation 82 can be efficiently tested in conjunction with managed pressure drilling. Furthermore, in certain examples described above, a pore pressure of theformation 82 can be readily determined.
The above disclosure provides to the art amethod 100 of testing anearth formation 82. Themethod 100 can include incrementally opening achoke 34 while drilling into theformation 82 is ceased, thereby reducing pressure in awellbore 12. Aninflux 84 into the wellbore 12 (due to reducing pressure in the wellbore 12) is detected.
Themethod 100 can also include verifying the pressure in thewellbore 12 with at least onepressure sensor 60 in thewellbore 12.
Themethod 100 can include ceasing circulation ofdrilling fluid 18 through adrill string 16 prior to incrementally opening thechoke 34. The method may also include verifying the pressure in thewellbore 12 with at least onepressure sensor 60 in thewellbore 12, after resuming circulation of thedrilling fluid 18 through thedrill string 16.
Incrementally opening thechoke 34 is typically performed multiple times. Incrementally opening thechoke 34 may cease when theinflux 84 is detected.
Detecting theinflux 84 can include detecting how fluid 18 flows out of thewellbore 12, and/or detecting when fluid flow out of the wellbore is greater thanfluid 18 flow into thewellbore 12.
Themethod 100 can include determiningapproximate formation 82 pore pressure as pressure in thewellbore 12 when theinflux 84 is detected. Determining theapproximate formation 82 pore pressure can include summing pressure in the annulus 20 near the surface with hydrostatic pressure in thewellbore 12, or determiningapproximate formation 82 pore pressure can include summing pressure in the annulus 20 near the surface with hydrostatic pressure in thewellbore 12 and friction pressure due to circulation of fluid through the wellbore.
Themethod 100 can also include, prior to incrementally opening thechoke 34, drilling into theformation 82, with an annulus 20 between adrill string 16 and thewellbore 12 being pressure isolated from atmosphere.
Also described above is themethod 100 of testing anearth formation 82, which method can include: drilling into theformation 82, with an annulus 20 between adrill string 16 and awellbore 12 being pressure isolated from atmosphere; ceasing circulation ofdrilling fluid 18 through thedrill string 16; detecting aninflux 84 into thewellbore 12 due to reduced pressure in thewellbore 12 while circulation is ceased; and determiningapproximate formation 82 pore pressure as pressure in thewellbore 12 when theinflux 84 is detected.
The above disclosure also describes themethod 100 of testing anearth formation 82, which method can include: drilling into theformation 82, with an annulus 20 between adrill string 16 and awellbore 12 being pressure isolated from atmosphere; then incrementally opening achoke 34 while drilling is ceased, thereby reducing pressure in thewellbore 12; detecting aninflux 84 into thewellbore 12 due to reducing pressure in thewellbore 12; and determiningapproximate formation 82 pore pressure as pressure in thewellbore 12 when theinflux 84 is detected.
Although themethod 100 is described above in conjunction with managed pressure drilling of thewellbore 12, it will be appreciated that the method can be practiced in conjunction with other drilling methods, such as, other drilling methods which include isolating the annulus 20 from the earth's atmosphere (e.g., using arotating control device 22 or other annular seal) at or near the surface. For example, themethod 100 could be used in conjunction with underbalanced drilling, any drilling operations in which the annulus 20 is pressurized at the surface during drilling, etc.
It is to be understood that the various embodiments of this disclosure described herein may be utilized in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without departing from the principles of this disclosure. The embodiments are described merely as examples of useful applications of the principles of the disclosure, which is not limited to any specific details of these embodiments.
In the above description of the representative examples, directional terms (such as "above," "below," "upper," "lower," etc.) are used for convenience in referring to the accompanying drawings. In general, "above," "upper," "upward" and similar terms refer to a direction toward the earth's surface along a wellbore, and "below," "lower," "downward" and similar terms refer to a direction away from the earth's surface along the wellbore, whether the wellbore is horizontal, vertical, inclined, deviated, etc. However, it should be clearly understood that the scope of this disclosure is not limited to any particular directions described herein.
Of course, a person skilled in the art would, upon a careful consideration of the above description of representative embodiments of the disclosure, readily appreciate that many modifications, additions, substitutions, deletions, and other changes may be made to the specific embodiments, and such changes are contemplated by the principles of this disclosure. Accordingly, the foregoing detailed description is to be clearly understood as being given by way of illustration and example only, the scope of the invention being limited solely by the appended claims and their equivalents.

Claims

A method of testing an earth formation, the method comprising:
reducing pressure in a wellbore (12); and
detecting an influx into the wellbore (12) due to the reducing pressure in the wellbore (12);characterized in that said pressure is reduced by incrementally opening a choke (34) while drilling into the formation is ceased.
A method as claimed in claim 1, further comprising, prior to incrementally opening the choke (34), drilling into the formation, with an annulus between a drill string (16) and the wellbore (12) being pressure isolated from atmosphere.
A method as claimed in claim 1, further comprising determining approximate formation pore pressure as pressure in the wellbore (12) when the influx is detected.
A method as claimed in claim 3, wherein determining approximate formation pore pressure comprises summing pressure in the annulus near the surface with hydrostatic pressure in the wellbore (12).
A method as claimed in claim 3, wherein determining approximate formation pore pressure comprises summing pressure in the annulus near the surface with hydrostatic pressure in the wellbore (12) and friction pressure due to circulation of fluid through the wellbore (12) .
A method as claimed in claim 3, further comprising:
drilling into the formation, with an annulus between a drill string (16) and a wellbore (12) being pressure isolated from atmosphere; wherein the method comprises said drilling and then said incrementally opening a choke (34).
A method as claimed in claim 1 or 6, further comprising verifying the pressure in the wellbore (12) with at least one pressure sensor in the wellbore (12).
A method as claimed in claim 1 or 6, further comprising ceasing circulation of drilling fluid through the drill string (16) prior to incrementally opening the choke (34) .
A method as claimed in claim 8, further comprising verifying the pressure in the wellbore (12) with at least one pressure sensor in the wellbore, after resuming circulation of the drilling fluid through the drill string (16) .
A method as claimed in claim 6, wherein incrementally opening the choke (34) is performed multiple times.
A method as claimed in claim 10, wherein incrementally opening the choke (34) ceases when the influx is detected.
A method as claimed in claim 6, wherein detecting an influx comprises detecting how fluid flows out of the wellbore (12).
A method as claimed in claim 6, wherein detecting an influx comprises detecting when fluid flow out of the wellbore (12) is greater than fluid flow into the wellbore (12) .
A method as claimed in claim 6, wherein determining approximate formation pore pressure comprises summing pressure in the annulus near the surface with hydrostatic pressure in the wellbore (12).
A method as claimed in claim 6, wherein determining approximate formation pore pressure comprises summing pressure in the annulus near the surface with hydrostatic pressure in the wellbore (12) and friction pressure due to circulation of fluid through the wellbore (12) .