AU2010303666A1 - Well drilling method utilizing real time response to ahead of bit measurements - Google Patents

Abstract

A well drilling method utilizing real time response to ahead of bit measurements. A well drilling method includes measuring a property of a portion of the earth prior to drilling a wellbore into the earth portion; and varying a drilling parameter in real time while drilling the wellbore, in response to measuring the property.

Description

WO 2011/044069 PCT/US2010/051384 WELL DRILLING METHOD UTILIZING REAL TIME RESPONSE TO AHEAD OF BIT MEASUREMENTS 5 CROSS-REFERENCE TO RELATED APPLICATIONS The present application is a continuation-in-part of Patent Cooperation Treaty application PCT/USO9/59541, titled "Well drilling method utilizing real time response to ahead of bit measurements" and filed Oct. 5, 2009 by inventors Sara Shayegi, Derrick W. 10 Lewis, Michael Bittar, James Randolph Lovom, and Craig W. Godfrey, and which is hereby incorporated herein by reference. TECHNICAL FIELD The present disclosure relates generally to equipment utilized and operations 15 performed in conjunction with a subterranean well and, in an embodiment described herein, more particularly provides a well drilling method utilizing real time response to ahead of bit measurements. BACKGROUND 20 In the past, properties of an earth formation have been estimated, modeled or predicted prior to drilling into the formation. However, the actual properties of a particular part of a formation are typically not known until after a drill bit drills into that part of the formation. Thus, operators in those circumstances cannot make proactive or preemptive decisions based on advance knowledge of the actual properties of the 25 formation prior to the drill bit cutting into the formation. BRIEF DESCRIPTION OF THE DRAWINGS FIG. 1 is a schematic partially cross-sectional view of a well drilling system which can embody principles of the present disclosure. 30 FIG. 2 is an enlarged scale schematic partially cross-sectional view to illustrate a method embodying principles of the present disclosure. FIG. 3 illustrates detection of a formation boundary prior to drilling into the formation boundary. FIG. 4 illustrates steering of a wellbore toward a desirable zone. 1 WO 2011/044069 PCT/US2010/051384 FIG. 5 illustrates detection of another wellbore prior to drilling into that wellbore. FIG. 6 is a flowchart of an illustrative method for real time or anticipatory response to ahead-of-bit measurements. 5 DETAILED DESCRIPTION Representatively and schematically illustrated in FIG. 1 is a well drilling system 10 and associated method which can incorporate principles of the present disclosure. In the system 10, a wellbore 12 is drilled by rotating a drill bit 14 on an end of a drill string 16. Drilling fluid 18, commonly known as mud, is circulated downward through the drill 10 string 16, out the drill bit 14 and upward through an annulus 20 formed between the drill string and the wellbore 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 the drilling fluid 18 upward through the drill string 16 (e.g., when connections are being made in the drill string). 15 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 accurately controlled to prevent excessive loss of fluid into the earth formation surrounding the wellbore 12, undesired fracturing of the formation, undesired influx of formation fluids into the wellbore, etc. In typical managed pressure drilling, it is desired 20 to maintain the bottom hole pressure just greater than a pore pressure of the formation, without exceeding a fracture pressure of the formation. 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. As explained below, a number of techniques can be used to control bottom hole pressure. 25 Gravity acts on the column of drilling mud flowing in and out of the hole, causing the fluid pressure to increase with depth. In the absence of dynamic flow effects, the rate of pressure increase is proportional to the fluid density. (Where the fluid is relatively incompressible, this results in a linear pressure increase with depth. Where the fluid density increases with pressure, gravity can produce an exponential pressure increase.) 30 Accordingly, one way to control pressure is to decrease the average fluid density by adding nitrogen or another gas, or another lighter weight fluid, to the drilling fluid 18. This technique is useful, for example, in underbalanced drilling operations. When dynamic flow effects are considered, a second technique for controlling bottomhole pressure becomes evident. When the drilling fluid flows slowly, dynamic 2 WO 2011/044069 PCT/US2010/051384 flow effects are minimal and the pressure distribution within the well is dominated by gravity effects. However at higher flow rates, the dynamic flow effects become increasingly important. As the fluid flows through the tubing and returns along the annulus, it experiences a frictional flow resistance which tends to create a linear pressure 5 drop along the fluid flow path. At sufficient flow rates these effects dominate over the gravity effects. Moreover, constrictions along the flow path can have a significant effect on the pressure profile, causing a pressure differential that raises upstream pressures and lowers downstream pressures. In some systems, a turbulent flow may develop, causing vortices and eddys which have similar effects to flow path constrictions. Accordingly, 10 such effects can be used to control bottom hole pressure, either by varying the flow rate or by varying downhole flow path constrictions or both. Another bottom hole pressure control method is illustrated in system 10. Here, 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 15 pressurized at or near the surface) using a rotating control device 22 (RCD). The RCD 22 seals about the drill string 16 above a wellhead 24. Although not shown in FIG. 1, the drill string 16 would extend upwardly through the RCD 22 for connection to, for example, a rotary table (not shown), a standpipe line 26, kelley (not shown), a top drive and/or other conventional drilling equipment. The drilling fluid 18 exits the wellhead 24 20 via a wing valve 28 in communication with the annulus 20 below the RCD 22. The fluid 18 then flows through drilling fluid return lines 30, 73 to a choke manifold 32, which includes redundant chokes 34 (only one of which may be used at a time). Backpressure is applied to the annulus 20 by variably restricting flow of the fluid 18 through the operative choke(s) 34. 25 The greater the restriction to flow through the choke 34, the greater the backpressure applied to the annulus 20. Thus, bottom hole pressure can be conveniently regulated by varying the backpressure applied to the annulus 20. A hydraulics model can be used to determine a pressure applied to the annulus 20 at or near the surface which will result in a desired bottom hole pressure, so that an operator (or an automated control 30 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 bottom hole pressure. Pressure applied to the annulus 20 can be measured at or near the surface via a variety of pressure sensors 36, 38, 40, each of which is in communication with the 3 WO 2011/044069 PCT/US2010/051384 annulus. Pressure sensor 36 senses pressure below the RCD 22, but above a blowout preventer (BOP) stack 42. Pressure sensor 38 senses pressure in the wellhead below the BOP stack 42. Pressure sensor 40 senses pressure in the drilling fluid return lines 30, 73 upstream of the choke manifold 32. Another pressure sensor 44 senses pressure in the 5 drilling fluid injection (standpipe) line 26. Yet another pressure sensor 46 senses pressure downstream of the choke manifold 32, but upstream of a separator 48, shaker 50 and mud pit 52. Additional sensors include temperature sensors 54, 56, Coriolis flowmeter 58, and flowmeters 62, 64, 66. Not all of these sensors are necessary. For example, the system 10 could include only two of the three flowmeters 62, 64, 66. However, input from the 10 sensors is useful to the hydraulics model in determining what the pressure applied to the annulus 20 should be during the drilling operation. Furthermore, the drill string 16 preferably includes at least one sensor 60. Such sensor(s) 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) 15 systems. 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, torque, rpm, weight on bit, stick-slip, etc.), formation characteristics (such as resistivity, density, etc.), fluid characteristics and/or other measurements. Various forms of telemetry (acoustic, pressure pulse, electromagnetic, 20 etc.) may be used to transmit the downhole sensor measurements to the surface. Alternatively, or in addition, the drill string 16 may comprise wired drill pipe (e.g., having electrical conductors extending along the length of the drill pipe) for transmitting data and command signals between downhole and the surface or another remote location. Additional sensors could be included in the system 10, if desired. For example, 25 another flowmeter 67 could be used to measure the rate of flow of the fluid 18 exiting the wellhead 24, another Coriolis flowmeter (not shown) could be interconnected directly upstream or downstream of a rig mud pump 68, etc. Pressure and level sensors could be used with the separator 48, level sensors could be used to indicate a volume of drilling fluid in the mud pit 52, etc. 30 Fewer sensors could be included in the system 10, if desired. For example, the output of the rig mud pump 68 could be determined by counting pump strokes, instead of by using flowmeter 62 or any other flowmeters. Note that the separator 48 could be a 3 or 4 phase separator, or a mud gas separator (sometimes referred to as a "poor boy degasser"). However, the separator 48 is 4 WO 2011/044069 PCT/US2010/051384 not necessarily used in the system 10. The drilling fluid 18 is pumped through the standpipe line 26 and into the interior of the drill string 16 by the rig mud pump 68. The pump 68 receives the fluid 18 from the mud pit 52 and flows it via a standpipe manifold 70 to the standpipe 26, the fluid then circulates downward through the drill string 16, 5 upward through the annulus 20, through the drilling fluid return lines 30, 73, through the choke manifold 32, and then via the separator 48 and shaker 50 to the mud pit 52 for conditioning and recirculation. Note that, in the system 10 as so far described above, the choke 34 cannot be used to control backpressure applied to the annulus 20 for control of the bottom hole pressure, 10 unless the fluid 18 is flowing through the choke. In conventional overbalanced drilling operations, such a situation will arise whenever a connection is made in the drill string 16 (e.g., to add another length of drill pipe to the drill string as the wellbore 12 is drilled deeper), and the lack of circulation will require that bottom hole pressure be regulated solely by the density of the fluid 18. 15 In the system 10, however, flow of the fluid 18 through the choke 34 can be maintained, even though the fluid does not circulate through the drill 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 the fluid 18 through the choke 34, even though a separate backpressure pump may not be used. Instead, the fluid 18 is flowed 20 from the pump 68 to the choke manifold 32 via a bypass line 72, 75 when a connection is made in the drill string 16. Thus, the fluid 18 can bypass the standpipe line 26, drill string 16 and annulus 20, and can flow directly from the pump 68 to the mud return line 30, which remains in communication with the annulus 20. Restriction of this flow by the choke 34 will thereby cause pressure to be applied to the annulus 20. 25 As depicted in FIG. 1, both of the bypass line 75 and the mud return line 30 are in communication with the annulus 20 via a single line 73. However, the bypass line 75 and the mud return line 30 could instead be separately connected to the wellhead 24, for example, using an additional wing valve (e.g., below the RCD 22), in which case each of the lines 30, 75 would be directly in communication with the annulus 20. Although this 30 might require some additional plumbing at the rig site, the effect on the annulus pressure would be essentially the same as connecting the bypass line 75 and the mud return line 30 to the common line 73. Thus, it should be appreciated that various different configurations of the components of the system 10 may be used, without departing from the principles of this disclosure. 5 WO 2011/044069 PCT/US2010/051384 Flow of the fluid 18 through the bypass line 72, 75 is regulated by a choke or other type of flow control device 74. Line 72 is upstream of the bypass flow control device 74, and line 75 is downstream of the bypass flow control device. Flow of the fluid 18 through the standpipe line 26 is substantially controlled by a valve or other type of 5 flow control device 76. Note that the flow control devices 74, 76 are independently controllable, which provides substantial benefits to the system 10, as described more fully below. Since the rate of flow of the fluid 18 through each of the standpipe and bypass lines 26, 72 is useful in determining how bottom hole pressure is affected by these flows, 10 the flowmeters 64, 66 are depicted in FIG. 1 as being interconnected in these lines. However, the rate of flow through the standpipe line 26 could be determined even if only the flowmeters 62, 64 were used, and the rate of flow through the bypass line 72 could be determined even if only the flowmeters 62, 66 were used. Thus, it should be understood that it is not necessary for the system 10 to include all of the sensors depicted in FIG. 1 15 and described herein, and the system could instead include additional sensors, different combinations and/or types of sensors, etc. A bypass flow control device 78 and flow restrictor 80 may be used for filling the standpipe line 26 and drill string 16 after a connection is made, and equalizing pressure between the standpipe line and mud return lines 30, 73 prior to opening the flow control 20 device 76. Otherwise, sudden opening of the flow control device 76 prior to the standpipe line 26 and drill 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 the choke manifold 32 temporarily being lost while the standpipe line and drill string fill with fluid, etc.). By opening the standpipe bypass flow control device 78 after a connection is made, the fluid 25 18 is permitted to fill the standpipe line 26 and drill string 16 while a substantial majority of the fluid continues to flow through the bypass line 72, thereby enabling continued controlled application of pressure to the annulus 20. After the pressure in the standpipe line 26 has equalized with the pressure in the mud return lines 30, 73 and bypass line 75, the flow control device 76 can be opened, and then the flow control device 74 can be 30 closed to slowly divert a greater proportion of the fluid 18 from the bypass line 72 to the standpipe line 26. Before a connection is made in the drill string 16, a similar process can be performed, except in reverse, to gradually divert flow of the fluid 18 from the standpipe line 26 to the bypass line 72 in preparation for adding more drill pipe to the drill string 16. 6 WO 2011/044069 PCT/US2010/051384 That is, the flow control device 74 can be gradually opened to slowly divert a greater proportion of the fluid 18 from the standpipe line 26 to the bypass line 72, and then the flow control device 76 can be closed. Note that the flow control device 78 and flow restrictor 80 could be integrated into 5 a single element (e.g., a flow control device having a flow restriction therein), and the flow 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 the standpipe line 26 and drill 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 10 equipped with the flow control device 76 in the form of a valve in the standpipe manifold 70, and use of the standpipe valve is incorporated into usual drilling practices, the individually operable flow control devices 76, 78 are presently preferred. The flow control devices 76, 78 are at times referred to collectively below as though they are the single flow control device 81, but it should be understood that the flow control device 81 15 can include the individual flow control devices 76, 78. Note that the system 10 could include a backpressure pump (not shown) for applying pressure to the annulus 20 and drilling fluid return line 30 upstream of the choke manifold 32, if desired. The backpressure pump could be used instead of, or in addition to, the bypass line 72 and flow control device 74 to ensure that fluid continues to flow 20 through the choke manifold 32 during events such as making connections in the drill string 16. In that case, additional sensors may be used to, for example, monitor the pressure and flow rate output of the backpressure pump. In other examples, connections may not be made in the drill string 16 during drilling, for example, if the drill string comprises a coiled tubing. The drill string 16 could 25 be provided with conductors and/other lines (e.g., in a sidewall or interior of the drill string) for transmitting data, commands, pressure, etc. between downhole and the surface (e.g., for communication with the sensor 60). As depicted in FIG. 1, a controller 84 (such as a programmable logic controller or another type of controller capable of controlling operation of drilling equipment) is 30 connected to a control system 86 (such as the control system described in Patent Cooperation Treaty application PCT/US08/87686, titled "Pressure and Flow Control in Drilling Operations" and filed Dec. 19, 2008 by inventors Lovorn, Bruder, Skinner, and Karigan). The controller 84 is also connected to the flow control devices 34, 74, 81 for regulating flow injected into the drill string 16, flow through the drilling fluid return line 7 WO 2011/044069 PCT/US2010/051384 30, and flow between the standpipe injection line 26 and the return line 30. The control system 86 can include various elements, such as one or more computing devices/processors, a hydraulic model, a wellbore model, a database, software in various formats, memory, machine-readable code, etc. These elements and others may be 5 included in a single structure or location, or they may be distributed among multiple structures or locations. The control system 86 is connected to the sensors 36, 38, 40, 44, 46, 54, 56, 58, 60, 62, 64, 66, 67 which sense respective drilling properties during the drilling operation. As discussed above, offset well data, previous operator experience, other operator input, 10 etc. may also be input to the control system 86. The control system 86 can include software, programmable and preprogrammed memory, machine-readable code, etc. for carrying out the steps of the method 90 described above. The control system 86 may be located at the wellsite, in which case the sensors 36, 38, 40, 44, 46, 54, 56, 58, 60, 62, 64, 66, 67 could be connected to the control system by wires or wirelessly. Alternatively, the 15 control system 86, or any portion of it, could be located at a remote location, in which case the control system could receive data via satellite transmission, the Internet, wirelessly, or by any other appropriate means. The controller 84 can also be connected to the control system 86 in various ways, whether the control system is locally or remotely located. 20 In one example, data signals from the sensors 36, 38, 40, 44, 46, 54, 56, 58, 60, 62, 64, 66, 67 are transmitted to the control system 86 at a remote location, the data is analyzed there (e.g., utilizing computing devices/processors, a hydraulic model, a wellbore model, a database, software in various formats, memory, and/or machine readable code, etc.) at the remote location. A decision as to how to proceed in the drilling 25 operation (such as, whether to vary any of the drilling parameters) may be made automatically based on this analysis, or human intervention may be desirable in some situations. Instructions as to how to proceed are then transmitted as signals to the controller 84 for execution at the wellsite. Even though all or part of the control system 86 may be at a remote location, the drilling parameter can still be varied in real time in 30 response to measurement of properties of the formation ahead of the bit, since modern communication technologies (e.g., satellite transmission, the Internet, etc.) enable transmission of signals without significant delay. It is not necessary for a surface choke to be used in the well control system and method. Instead, a downhole choking/flow restricting device could be used. The 8 WO 2011/044069 PCT/US2010/051384 downhole choke could, for example, comprise an inflatable packer on the drill string to choke flow through the annulus. Inflation of the packer and the resulting flow restriction could be controlled so that a desired downhole pressure is achieved/maintained. Alternatively a variable orifice could be used within the drillstring and actuated in 5 response to external parameter measurements including flow rates and pressure. Downhole flow measurement system and/or a PWD (downhole pressure measurement system) can be used for early influx detection. Detected changes in pressure, flow, fluid type, etc., may provide rapid detection of formation fluid influx to the borehole and enable fast response. Preferably, the well control system stops an undesired influx and 10 circulates the influx fluid out of a well, using a hydraulics model to automatically control the choke or flow restrictors based on a desired surface pressure profile and desired downhole pressure. Such a system can prevent break down of a casing shoe, and can be remotely monitored and controlled. Referring additionally now to FIG. 2, an enlarged scale schematic partially cross 15 sectional view of the drill string 16 as it is being used in a method 90 for drilling the wellbore 12 is representatively illustrated apart from the remainder of the system 10. However, it should be clearly understood that the method 90 may be practiced with other well drilling systems in keeping with the principles of this disclosure. FIG. 2 shows a sensor 60 connected in close proximity to the drill bit 14. For example, the sensor 60 may 20 be positioned between the drill bit 14 and a fluid motor 94 (e.g., a "mud" motor) used to rotate the drill bit in response to flow of the drilling fluid 18 through the motor. In other embodiments, the sensor can be partly or fully integrated into the drill bit. In this example, the sensor 60 is capable of measuring one or more properties of a portion 92 of the earth prior to the drill bit 14 cutting into the earth portion. For example, 25 the sensor 60 may measure a property of an earth formation approximately 10 to 50 feet (-3 to 17 meters) ahead of the bit 14. More advanced sensors may be capable of measuring a property of an earth formation up to about 100 feet (~30 meters) ahead of the bit 14. However, it should be understood that measurement of formation properties at any distance ahead of the bit 14 may be used, in keeping with the principles of this disclosure. 30 Contemplated look-ahead sensors include resistivity logging tools, radar tools, acoustic tools, nuclear radiation tools, and combinations thereof. These various technologies are each discussed in turn below. A number of logging tools have been developed that can provide look-ahead capabilities including, for example, those described in U.S. Pat. 6,181,138 "Directional 9 WO 2011/044069 PCT/US2010/051384 resistivity measurements for azimuthal proximity detection of bed boundaries" filed Feb. 22, 1999 by inventors Hagiwara and Song, U.S. Pat. 6,480,118 "Method of drilling in response to looking ahead of drillbit" filed March 27, 2000 by inventor Vikram Rao, U.S. Pat. 6,958,610 "Method and apparatus measuring electrical anisotropy in formation 5 surrounding a wellbore" filed June 17, 2002 by inventor Stanley Gianzero, U.S. Pat. 7,350,568 "Logging a well" filed February 9, 2005 by inventors Mandal and Bittar, and PCT application "Deep Evaluation of Resistive Anomalies in Borehole Environments" filed Oct. 5, 2009 by inventors Bittar and Donderici (agent file reference 09-021339). That is, previously disclosed resistivity tools can be configured to measure 10 galvanic resistivities of formations ahead of the bit by using the bit to inject current into the surrounding formation and using a plurality of return electrodes to isolate the contribution of the currents flowing through formation portion 92 ahead of the bit. To accomplish this, the geometrical spreading of currents from the injection electrode to each of the return electrodes is modeled and used to identify that combination of measurements 15 which is most representative of the resistivity ahead of the bit. Similarly, one or more horizontal or tilted magnetic dipole antennas can induce current flows in the formations around the drill bit and an array of receivers can isolate the measurement contributions of those currents flowing in the regions ahead of the bit to measure resistivity and/or dielectric constant. It is even possible to modify a drillstring radar system (such as that 20 described in U.S. Pat. 6,778,127 "Drillstring Radar" filed Nov. 4, 2002 by inventors Stolarczyk and Stolarczyk) to provide a look ahead capability. A waveguide directs a series of high-power radar pulses or a modulated continuous wave electromagnetic signal forward from the bit. The receiver signals are then analyzed to detect signal reflections from which target strength and distance can be measured. Further processing can be 25 performed to estimate the dielectric constant of the formations traversed by the radar signals. Many of the above mentioned references also discuss acoustic look-ahead measurements. In some embodiments, acoustic pulses are transmitted forward from the bit and received with acoustic transducers. Analysis of the received signals indicates 30 travel time to those sources of acoustic signal reflections. When combined with measurements or estimates of acoustic velocities, such travel times can be readily converted to target distances. Other embodiments rely on the drilling noise as an acoustic source and apply a correlation processing technique to the received signals to observe and measure signal reflections. As with the resistivity tools, an array of receivers can be 10 WO 2011/044069 PCT/US2010/051384 employed to improve tool performance and/or to provide beam steering. (When the signals from the receiver array are combined in the appropriate fashion, the array can be "focused" to enhance signals arriving from a given direction and to suppress signals arriving from other directions.) In addition to identifying boundaries, fractures, and 5 interfaces, acoustic signal measurements can provide estimates of formation density and, in some cases, formation breakdown or fracture pressures. Neutron and gamma ray tools can also be used for look-ahead measurements. Though the range of such tools is generally much more limited than that of resistivity or acoustic tools, neutron tools can still be expected to have a range of up to a meter under 10 the right conditions. An important consideration in maximizing the range of such tools is placing the detector as near the end of the drillstring as feasible, and preferably in the bit itself. It is expected that the detector would take the form of a scintillation detector, which measures gamma ray flux by the count rate of flashes in a scintillation crystal. Note that measurements of natural gamma ray radiation can be combined with resistivity 15 measurements to estimate pore pressure. See, e.g., W.A. Zoeller, "Pore Pressure Detection from the MWD Gamma Ray", SPE 12166, 1983. Pore pressure trends can be combined with overburden pressure information to predict fracture pressures. See, e.g., V.A. Akinbinu, "Prediction of fracture gradient from formation pressures and depth using correlation and stepwise multiple regression techniques", J. Petroleum Sci. Engr., 72(1), 20 pp. 10-17, May 2010. Sensor 60 can use any one or more of these techniques to measure resistivity, dielectric constant, acoustic impedance, natural radioactivity, prompt gamma response to neutrons, and/or other properties of the formation ahead of the bit. The sensor measurements can be used to measure porosity of the earth portion 92, pore pressure in 25 the earth portion, fracture pressure of the earth portion, density of the earth portion, strength of the earth portion, fluid type in the earth portion, and/or other properties. Furthermore, by measuring multiple such properties of the earth portion 92, the tool can identify the presence of a water interface, a gas interface, an oil interface, salt, a fault, a formation boundary and/or another wellbore, etc. in the earth portion. Some tool 30 embodiments may further identify lithology based on gamma, density, and resistivity measurements, and may warn of imminent fracture pressure changes, rate of penetration changes, etc. Based on pore pressure profiles, the system can also alert the operator to potential bypass flows before the borehole connects the candidate formations. 11 WO 2011/044069 PCT/US2010/051384 Note that the method 90 includes actually measuring one or more properties of the earth portion 92 prior to drilling into the earth portion, rather than merely predicting or estimating what such properties should be based, for example, on offset well data, models, etc. Instead, the method 90 enables a drilling parameter (such as choke position, 5 operation of a flow control device, drill bit steering, drilling fluid weight, torque, rpm, bit type, weight on bit, etc.) to be varied in real time, in response to the actual measurement of at least one property of the earth portion 92 prior to drilling into that earth portion. This capability can be very valuable in a drilling operation. For example, control of drilling parameters in response to real time measurement of formation properties ahead 10 of the drill bit 14 can be used to proactively adjust flow control devices 34, 74, 81 (e.g., to compensate for increased or decreased pore pressure in the earth portion 92, to compensate for increased or decreased fracture pressure of the earth portion, to maintain a desired bottom hole pressure, etc.), to guide a determination of whether and where to set casing (e.g., when a margin between pore and fracture pressure indicates that casing 15 should be set, waiting until a high strength or increased pressure zone is drilled into, etc.), to avoid drilling into a water-bearing zone, to avoid drilling into an existing open or cased wellbore, to avoid or steer into salt, to avoid or steer into a fault, fracture, karst or formation boundary, to continue drilling through or to steer toward a hydrocarbon bearing zone, etc. 20 Referring additionally now to FIG. 3, the method 90 is representatively illustrated in the situation where a formation boundary 95 exists in the earth portion 92 which is in the path of the wellbore 12 as it is being drilled. One type of earth formation 96 is positioned on one side of the boundary 94, and another type of earth formation 98 is positioned on the other side of the boundary. Using the sensor 60, the presence of the 25 formation boundary 95 can be detected in real time prior to drilling into the boundary, and so various pertinent decisions can be made in a timely, proactive or even preemptive manner. Furthermore, the sensor 60 can measure properties of the formations 96, 98 for use in the decision-making process. For example, if it is determined that the formation 98 comprises shale, then it may be desirable to make preparations for increasing bottom hole 30 pressure in the wellbore 12 somewhat (e.g., by increasing the weight of the drilling fluid 18, increasingly restricting flow through the choke 34, and/or altering the flow rate). If it is determined that the formation 98 comprises salt, then a decision may be made to either drill into, avoid or steer away from the formation boundary 95. If it is determined that the formation 98 comprises a water-bearing zone, then a decision may be made to avoid or 12 WO 2011/044069 PCT/US2010/051384 steer away from the formation boundary 95 (unless, of course it is desired to drill into a water-bearing zone, for example, in a disposal or conformance operation, etc.). If it is determined that the formation 98 comprises a hydrocarbon-bearing zone, then a decision may be made to steer toward and drill into the formation, delay setting casing until after 5 drilling into the formation, etc. If it is determined that the formation 98 has a significantly different pore or fracture pressure, or a significantly different margin between pore and fracture pressures, as compared to the formation 96, then it may be desirable to: a) make preparations for increasing or decreasing bottom hole pressure in the wellbore 12 accordingly, b) avoid 10 drilling into the formation 98, c) set casing prior to drilling into the formation 98, d) continue to drill ahead into the formation 98 prior to setting casing, or e) steer toward or away from the formation 98, etc. If it is determined that the formation 98 is a higher strength or more stable formation as compared to the formation 96, then a decision may be made to delay setting casing until after drilling into the formation 98. If it is 15 determined that the formation 98 should be drilled using another type of drill bit, then the drill bit 14 may be replaced with the other type of drill bit prior to, or just as, the formation 98 is drilled into. For example, it may be beneficial to change between a tri cone rock bit and a fixed cutter PDC bit, depending on the characteristics of the formations 96, 98. 20 Referring additionally now to FIG. 4, the method 90 is representatively illustrated in another example for which the principles of this disclosure may be used advantageously. The drill string 16 is not depicted in FIG. 4, but it will be understood that, as described above, the drill string would be used for drilling the wellbore 12 in the direction indicated by arrow 100. In this example, it is desired to continue drilling the 25 wellbore 12 through a hydrocarbon-bearing zone 102, and to avoid drilling into a water bearing zone 104. The capability of measuring properties of the earth portion 92 in the path of the wellbore 12, as described above, enables steering of the wellbore so that it stays in the zone 102 and avoids the zone 104. Furthermore, formation anomalies (such as a fracture, karst or fault 106 in the path of the wellbore 12) can be detected before drilling 30 into the anomalies, so that pertinent decisions (whether to steer toward, drill into or avoid the fault, etc.) can be made beforehand. If, in the example of FIG. 4, the decision is made to drill through the fault 106, then the wellbore 12 could be steered so that it continues to drill through the zone 102 on an opposite side of the fault. 13 WO 2011/044069 PCT/US2010/051384 Referring additionally now to FIG. 5, the method 90 is representatively illustrated in another example for which the principles of this disclosure may be used advantageously. In this example, it is desired to avoid drilling into another wellbore 108 previously drilled into the earth in the path of the wellbore 12. If the wellbore 108 is 5 present in the earth portion 92 ahead of the bit 14, then the sensor 60 can detect the presence of the wellbore (for example, due to the change in density, etc.), whether the wellbore is open hole or has casing 110 therein. In response, the wellbore 12 can be steered to avoid drilling into the other wellbore 108. FIG. 6 provides a flowchart to further illustrate the various stages of the look 10 ahead response method. Beginning in block 602 the drillers assemble a drilling system that, among other things, provides continuous and adjustable control of bottomhole pressure using any one or more of the techniques described above. The drilling system would naturally also permit control of other downhole drilling parameters such as rotations per minute (RPM), weight on bit (WOB), rate of penetration (ROP), and 15 steering direction. (To control this last parameter, the drillstring may include a steering assembly such as a rotary steerable system or hydraulically actuated steering fins.) The assembled system includes one or more look-ahead sensors in the drillstring's bottomhole assembly. In block 604, the drilling system uses these sensors to collect look-ahead measurements during the drilling process. The sensors can employ any one or more of the 20 previously discussed techniques to detect faults, boundaries, boreholes, fluid interfaces, and/or formation properties such as density, pore pressure, and fracture pressure. In block 606 the system (typically, though not necessarily, in a data processing unit at the surface) combines the look ahead measurements with the other available data including borehole logs to determine the desired drilling parameters at one or more 25 positions ahead of the bit. Thus, for example, the system may determine the bottom hole pressure that would be desirable at the time when the bit reaches the region being surveyed by the look-ahead sensors, or it may determine the desired steering direction that would be desirable at that time. In block 608, the system determines whether an alarm condition exists, i.e., whether the desired drilling parameters would be 30 incompatible with existing borehole conditions or with the capabilities of the drilling system. This situation could arise where the desired bottom hole pressure would be too high for some of the previously penetrated formations to tolerate (e.g., high enough to cause undesired fracturing and/or fluid loss from the borehole), or too high for the seals on the well head. Conversely, the desired bottomhole pressure could be too low, enabling 14 WO 2011/044069 PCT/US2010/051384 fluid inflows from other formations that could lead to a blow out or to bypass flows from one formation to another via the borehole. Other alarm examples include faults, boreholes, boundaries, or interfaces that are desirable to avoid, but which the steering apparatus is incapable of steering around. 5 If an alarm condition is detected, an alarm is activated in block 610 to alert the drilling operator to halt drilling or to re-evaluate the situation before proceeding cautiously. In block 612, the drilling system employs position and rate of penetration measurements to determine the timing for adjusting the drilling parameters to the desired drilling parameters. Thus, for example, the system can maintain the bottomhole pressure 10 at a value that provides optimal drilling conditions for the current formation, and can avoid changing that pressure too early or too late. Of course, the desired parameter values and timing can be adjusted as drilling progresses and the drilling path changes or the look-ahead measurements for a given portion of the formation are refined. In block 614, the drilling system operates at the selected time to signal the automatic controls and/or the 15 drilling operator to change the drilling parameter to the desired values. Thus, for example, the system may increase fluid density and/or increase back pressure to bring up the bottomhole pressure just before the bit contacts a high pore pressure formation. At least some method embodiments include a margin to allow for timing errors. In block 616, the system determines whether drilling has halted and if so, the method completes. Otherwise 20 the various blocks are repeated beginning with block 604. It may now be appreciated that the above disclosure provides many benefits to the art of well drilling. The system 10 and method 90 enable drilling operations to be controlled based on real time measurements of formation properties ahead of the drill bit 14. More specifically, the above disclosure provides to the art a drilling method 90 which 25 includes measuring a property of a portion 92 of the earth prior to drilling a wellbore 12 into the earth portion 92; and varying a drilling parameter in real time while drilling the wellbore 12, in response to measuring the property. The earth portion 92 may be at least initially in a path of a drill bit 14 being used to drill the wellbore 12. Measuring the property may include measuring at least one of resistivity of the earth portion 92, acoustic 30 impedance of the earth portion 92, and gamma counts due to gammas emanating from the earth portion 92. Measuring the property may include measuring at least one of porosity of the earth portion 92, pore pressure in the earth portion 92, fracture pressure of the earth portion 92, density of the earth portion 92, strength of the earth portion 92, and fluid type in the earth portion 92. Measuring the property may include detecting the presence of at 15 WO 2011/044069 PCT/US2010/051384 least one of water, hydrocarbon fluid, salt, a fault 106, a formation boundary 95 and another wellbore 108. Measuring the property may include receiving at least one of a geochemical signal, an isotope reading and a chromatograph reading indicative of the property of the earth portion 92. Measuring the property may include characterizing a 5 fluid in the earth portion. Measuring the property may include detecting the presence of at least one of a fracture and a karst in the earth portion 92. Measuring the property may be performed utilizing a resistivity sensor 60 positioned between a fluid motor 94 and a drill bit 14 in a drill string 16 used to drill the wellbore 12. Varying the drilling parameter may include varying pressure in the wellbore 12. 10 Varying pressure in the wellbore 12 may include adjusting a flow control device 34, 74, 76, 78, 81. The flow control device 34 may variably restrict flow through a return line 30 for discharging drilling fluid 18 from an annulus 20 formed between the wellbore 12 and a drill string 16. The flow control device 81 may variably restrict flow through a standpipe line 26 for injecting drilling fluid 18 into a drill string 16 used to drill the 15 wellbore 12. The flow control device 74 may variably restrict flow between a standpipe line 26 for injecting drilling fluid 18 into a drill string 16 used to drill the wellbore 12 and a return line 30 for discharging drilling fluid 18 from an annulus 20 formed between the wellbore 12 and the drill string 16. Varying pressure in the wellbore 12 may be performed in response to at least one of: determining that the earth portion 92 comprises shale, 20 determining that a pore pressure of the earth portion 92 is greater than that of an already drilled portion, determining that the pore pressure of the earth portion 92 is less than that of the already drilled portion, determining that a fracture pressure of the earth portion 92 is greater than that of the already drilled portion, determining that the fracture pressure of the earth portion 92 is less than that of the already drilled portion, and determining that 25 the earth portion 92 comprises a formation boundary 95. Varying the drilling parameter may include adjusting a flow control device 34, 74, 81, thereby maintaining a desired pressure in the wellbore 12. Varying the drilling parameter may include steering the wellbore 12 and thereby continuing to drill in a hydrocarbon-bearing zone 102. Varying the drilling parameter may include steering the 30 wellbore 12 toward the hydrocarbon-bearing zone 102. Varying the drilling parameter may include steering the wellbore 12 toward or away from a water-bearing zone 104. Varying the drilling parameter may include steering the wellbore 12 toward or away from a fault 106, toward or away from a formation boundary 95, and/or toward or away from 16 WO 2011/044069 PCT/US2010/051384 another wellbore 108. Varying the drilling parameter may include changing a drill bit 14 on a drill string 16 used to drill the wellbore 12. The method 90 may also include transmitting a signal representative of the measured property to a remote location for analysis prior to varying the drilling 5 parameter. During the drilling parameter varying, pressure in the wellbore 12 may be greater than, equal to, or less than pore pressure in an earth formation exposed to the wellbore 12. It is to be understood that the various embodiments of the present disclosure described above may be utilized in various orientations, with various types of wellbores 10 and well drilling systems, 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. Of course, a person skilled in the art would, upon a careful consideration of the above description of representative embodiments of the disclosure, 15 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 the present disclosure. Accordingly, the foregoing detailed description is to be clearly understood as being given by way of illustration and example only, the spirit and scope of the present invention being limited solely by the appended 20 claims and their equivalents. In the above description of the representative embodiments of the disclosure, 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 25 wellbore, and "below," "lower," "downward" and similar terms refer to a direction away from the earth's surface along the wellbore. 17

Claims (21)

1. A well drilling method, comprising: collecting ahead-of-bit measurements while drilling; 5 determining a desired value of at least one drilling parameter based at least in part on the ahead-of-bit measurements; and providing an adjustment to the drilling parameter to match the desired value, wherein said providing includes using a rate-of-penetration measurement to determine timing for said adjustment. 10

2. The method of claim 1, wherein the at least one drilling parameter comprises bottom hole pressure.

3. The method of claim 2, further comprising estimating a formation pore pressure based at least in part on the ahead-of-bit measurements.

4. The method of claim 3, further comprising estimating a formation fracture pressure 15 based at least in part on the ahead-of-bit measurements.

5. The method of claim 2, further comprising verifying that the desired value of the drilling parameter is suitable for previously penetrated formations.

6. The method of claim 5, further comprising activating an alarm if the desired value is not suitable for previously penetrated formations. 20

7. The method of claim 1, wherein the ahead-of-bit measurements include formation resistivity.

8. The method of claim 1, wherein the ahead-of-bit measurements include at least one of acoustic velocity, acoustic impedance, and formation density.

9. The method of claim 1, wherein the ahead-of-bit measurements include at least one of 25 natural gamma radiation, prompt gamma response to neutron radiation, and formation porosity.

10. The method of claim 1, further comprising processing the ahead-of-bit measurements to identify a position of at least one of a bed boundary, a formation fluid interface, a fracture, and a borehole. 30

11. The method of claim 10, wherein the drilling parameter comprises a steering direction.

12. A well drilling system that comprises: a drillstring having at least one tool that collects look-ahead measurements; and 18 WO 2011/044069 PCT/US2010/051384 a control system that regulates a drilling parameter based at least in part on the look ahead measurements.

13. The system of claim 12, wherein the control system further regulates the drilling parameter based at least in part on timing information derived partly from rate of 5 penetration measurements.

14. The system of claim 13, wherein the drilling parameter comprises bottomhole pressure.

15. The system of claim 14, wherein the control system determines formation pore pressure based at least in part on the ahead-of-bit measurements. 10

16. The system of claim 14, wherein the control system determines formation fracture pressure based at least in part on the ahead-of-bit measurements.

17. The system of claim 14, wherein the control system verifies that a desired value of the drilling parameter is suitable for previously penetrated formations and activates an alarm if the desired value is not suitable for previously penetrated formations. 15

18. The system of claim 12, wherein the look-ahead measurements include at least one of formation resistivity and dielectric constant.

19. The system of claim 12, wherein the look-ahead measurements include at least one of acoustic velocity, acoustic impedance, and formation density.

20. The system of claim 12, wherein the look-ahead measurements include at least one of 20 natural gamma radiation, prompt gamma response to neutron radiation, and formation porosity.

21. The system of claim 12, wherein the drilling parameter comprises a steering direction, and wherein the control system further processes the look-ahead measurements to identify a position of at least one of a bed boundary, a formation fluid interface, a fracture, and a 25 borehole. 19