WO2017199104A1

WO2017199104A1 - Method for improving drilling direction accuracy and knowledge of drilling direction

Info

Publication number: WO2017199104A1
Application number: PCT/IB2017/050757
Authority: WO
Inventors: Henning Hansen; Tarald Gudmestad
Original assignee: Aarbakke Innovation As
Priority date: 2016-05-16
Filing date: 2017-02-10
Publication date: 2017-11-23

Abstract

A method for determining spatial position of a drill bit during drilling of a subsurface wellbore includes measuring acoustic signals generated by operating the drill bit to drill subsurface formations using an acoustic sensor proximate the drill bit. Acoustic signals are measured at a plurality of known, spaced apart locations on a land surface above the wellbore or on the bottom of a body of water above the wellbore. Travel time of the acoustic signals from the drill bit to each known, spaced apart location is determined using the measured drill bit signals and the measured signals at the plurality of locations. The spatial position of the drill bit is determined using the determined travel times.

Description

METHOD FOR IMPROVING DRILLING DIRECTION ACCURACY AND KNOWLEDGE OF DRILLING DIRECTION

Background

[0001] This disclosure relates to the field of drilling underground wellbores, where accurate wellbore trajectory knowledge is required. More specifically, the disclosure relates to methods and apparatus for determining trajectory direction of underground wellbores during drilling.

[0002] Accurate knowledge of a wellbore' s trajectory underground is important to for reasons, as for example, accurately and rapidly drilling a "relief well" into an existing wellbore for well relief or killing, in case of an abnormal situation in or with the existing wellbore, e.g., a blow-out or uncontrolled flow of formation fluid from the existing wellbore. The less time it takes to intercept the first wellbore, the less environmental damage or risk of such will be the result. Also, great cost savings may be obtained by rapid intersection of a relief well with an existing well.

[0003] If a high inclination, as for example a horizontal wellbore is not placed optimally through a hydrocarbon bearing formation, substantial reduction of or no production of hydrocarbons can be the result.

[0004] Increased geodetic accuracy of mapping existing and future wellbores reduces the risk of wellbore collision by a later drilled wellbore and consequent sudden and undesired flow of hydrocarbons to surface through the colliding wellbore.

[0005] Increased accuracy of measurement or determination of wellbore trajectory direction may also allow parallel well placement, e.g., producer-injector- producer wellbores drilled at high inclination through a subsurface hydrocarbon producing formation. See, for example, U.S. Patent No. 8,490,965 and U.S. Patent No. 8,517,091 both issued to Bahorich et al.

[0006] Wellbore drilling along a selected trajectory may use directional sensors such as a combination of three-axis magnetic directional sensors (e.g., flux gate magnetometers) and acceleration sensors to detect the direction of Earth's gravity to enable determining a geodetic direction of the wellbore and a geodetic direction of the sensor (which is usually located close enough to a drill bit to infer the well direction at the drill bit).

[0007] In high latitude areas of the Earth, strong magnetic disturbances and the nature of the Earth's magnetic field cause uncertainties in the knowledge of the trajectory of a wellbore. Gyroscopic directional measurement is known to be used instead of magnetic directional measurement for increased accuracy, however, at high latitude the geodetic reference accuracy and therefore also the overall well placement with gyroscopic directional surveying may be reduced. Uncertainties in geodetic direction and resulting calculated position from 20 to 50 meters along a horizontal wellbore trajectory have been identified in high latitude areas as for example the Barents Sea. Such uncertainty with respect to the planned wellbore trajectory can result in uneconomic wellbores and field developments, and may also cause concerns regarding the difficulties that may be observed if a relief well is to be drilled to intersect a problematic wellbore.

[0008] There is a need for a device and method that can provide substantial improvements in wellbore trajectory determination.

[0009] Passive seismic (microseismic) monitoring for wellbore stimulation (also called

"tracking") is widely used to determine depth, direction and location of fracturing or rupturen of the reservoir rock as a result of injecting fluids to enable or increase the production of hydrocarbons from certain low permeability formations. Also, devices such as acoustic listening devices may be used at the Earth's surface, water surface or water bottom for 4D (time lapse) seismic surveying. In addition, spatially distributed seismic sensors, e.g., fiber optic distributed cable sensors known in the art can detect and sample acoustic events taking place in areas remote from such cables. It may be possible to use such technologies to identify the underground spatial (e.g., Cartesian coordinate position X, Y, and Z with respect to a selected origin) location of acoustic energy created by a device such as a drill bit, an active (controlled) acoustic source, and the like. Brief Description of the Drawings

[0010] Fig. 1 illustrates an underground wellbore trajectory.

[0011] Fig. 2 illustrates a drilling rig creating an underground wellbore.

[0012] Fig. 2A illustrates magnetic field and gravitational acceleration measurements made by a directional sensor package shown in Fig. 2.

[0013] Fig. 3 illustrates a wellbore being drilled underground, as seen from above, where two listening devices are located in the direction of where the wellbore is to be placed.

[0014] Fig. 4 illustrates a sound detecting cable placed on the ground or on the seafloor, where the cable contains acoustic receivers or is using so called distributed acoustic sensing.

Detailed Description

[0015] Methods according to the present disclosure may include measuring the Earth's magnetic field along orthogonal directions in the subsurface and changes to measurements of the Earth's magnetic field caused by a drilling system penetrating formations in the subsurface. The magnetic field measurements may be cross referenced to, for example, acoustic location detection measurements and thus a more accurate position of a drilling system in the subsurface (e.g., in Cartesian coordinates, X, Y, Z with reference to a selected origin) may also be determined.

[0016] In methods according to the present disclosure, using one or several acoustic sensing devices when combined with magnetic and gravitational measurements as set forth in the Background section herein may provide accurate geodetic location of a drill bit and/or drilling tool assembly used to penetrate underground formations. An acoustic energy source, for example in the form of a hammer device powered and operated by drilling fluid mud flow through a drill string, may be used as an acoustic energy source such that an acoustic sensor or array of acoustic sensors may be used to locate and monitor the position of the drill bit and/or drilling tool assembly. [0017] By analyzing the detected acoustic energy it may be possible to determine underground formation properties and expected drilling conditions ahead of the drill bit in a direction toward one or several acoustic sensors. Such properties may include the type of fluids present in the formations, e.g., gas, open caves and the like, where it may also be possible to determine the location of and distance to such cave, gas, etc. Also, by acoustic energy created by the drill bit, it may be possible to determine the condition of the drill bit, efficiency of the drilling penetration, and other drilling parameters.

[0018] A method according to the present disclosure may also be performed by a well intervention in a previously drilled wellbore, where an acoustic energy source is deployed into the previously drilled wellbore by, for example wireline, jointed or spooled tubing, etc. By the foregoing use of an acoustic energy source, a more accurate mapping of the wellbore trajectory can be obtained in wellbores where above described method was not used when drilling the well.

[0019] Fig. 1 illustrates an underground wellbore well path or trajectory W. The origin

(0,0,0) of the trajectory W may be referenced to the drill center (not shown) of a drilling unit (not shown) disposed on the land surface or on the surface of a body of water, depending on whether the wellbore is drilled below the land surface or below the water bottom. A point along the trajectory W, which in the present example embodiment is the endmost point along the trajectory W may be indicated by its Cartesian coordinates XI, Yl, Zl with reference to the origin (0,0,0). It is to be understood that Cartesian coordinates used to indicate the position of any point along the well trajectory W is not a limitation on the scope of the present disclosure. Any other known coordinate system, including for example and without limitation cylindrical and spherical coordinates may be used to equal effect.

[0020] Fig. 2 illustrates a drilling unit D creating an underground wellbore WB. Details of the drilling unit D and devices used to create the underground wellbore WB are well known in the art and need not be explained herein in order to explain how to make and use methods and apparatus according to the present disclosure. Submerged underground at a selected position with reference to the drilling unit D, a passive listening device 12 (e.g., an acoustic sensor such as a geophone or hydrophone) detects noise created by equipment such as a drill bit 14 as the drill bit 14 penetrates the subsurface formations. Although the illustrated a drilling unit D in Fig. 2 is placed on the land surface, it shall be understood that the drilling unit D may also be a marine drilling rig (floating, or set on the seabed) located offshore, where the passive listening device 12 is placed on or below the seabed. Acoustic energy 10 generated by the drill bit 14 is shown traveling from the position of the drill bit 14 (shown as Cartesian position XI, Yl, Zl) to the passive listening device 12. In the present example embodiment, a directional sensor package 13 may be disposed in a drill string 11 used to rotate and move the drill bit 14. The directional sensor package 13 may be part of a "measurement while drilling" (MWD) system known in the art. Measurements made by sensors in the directional sensor package 13 of Fig. 2 are shown schematically in Fig. 2A. The directional sensor package 13 may comprise three, mutually orthogonal magnetic field sensors, for example, flux gate magnetometers, which measure a magnitude of the magnetic field along each of three orthogonal component directions. In the embodiment shown in Fig. 2A, the components are Mz, which is the magnetic field component amplitude along the longitudinal axis of the directional sensor package 13 (and correspondingly along the longitudinal axis of the wellbore at the location of the directional sensor package 13). Two orthogonal components of the magnetic field in a plane normal to the Mz direction are shown at Mx and My. Gravitational acceleration sensors having sensitive axes disposed correspondingly to the magnetic field sensors are shown, respectively, at Gz, Gx and Gy. The relative magnitudes of each measured component magnetic field direction, Mz, Mx, My with respect to the total magnetic field M:

may be used with the component magnitude measurements of Earth's gravity, wherein G represents the total gravitational field of the Earth:

•J' Gx² + Gy² + Gz² to determine the geodetic orientation of the directional sensor package 13 proximate the position of the drill bit 14. The geomagnetic direction determined from the above expression may differ from the geodetic direction based on, among other factors, the difference between the geomagnetic North direction at the location of the wellbore WB, the "dip" of the Earth's magnetic field (inclination of the magnetic field toward the ground surface or water bottom) at the location of the wellbore WB, and magnetic interference from sources such as rotation of ferromagnetic sections of the drill string 11 in the Earth's magnetic field. In combination, the foregoing sources of difference between geomagnetic direction and geodetic direction may cause uncertainty and error in determining the actual geodetic orientation of the directional sensor package 13. Such errors are cumulative along the wellbore WB as it is lengthened; thus the uncertainty of the geodetic position of the drill bit 14 increases with respect to the length (measured depth) of the wellbore WB. In methods according to the present disclosure, a determined geodetic position of the drill bit at one or more points along the well trajectory may be used to calibrate the geodetic position of the directional sensor package 13 at selected positions along the well trajectory. The calibrated positions may be used to "reset" the uncertainty to a minimum value (i.e., at the same amount of uncertainty as at the beginning of the wellbore WB. Fig. 3 illustrates a wellbore WB being drilled underground, as observed from above (e.g., in a plane where Z is non-zero), where two passive listening devices 12A, 12B are located on opposed sides of the direction 16 along which the wellbore WB is to be drilled. The passive listening devices 12A, 12B detect noise from the drill bit 14, and data from both passive listening devices 12 A, 12B are compared to accurately describe the geodetic location of the drill bit 14. One such comparison may comprise acoustic energy travel time from the drill bit 14 to each passive listening device 12A, 12B. Acoustic energy travel time may be determined, for example, by cross-correlating a pilot noise signal detected by an acoustic sensor 17A proximate the drill bit 14 or proximate the drilling unit at 17B with the signals detected by each of the passive listening devices 12A, 12B. Travel time thus determined may be used in connection with an acoustic velocity distribution model generated, for example from surface reflection seismic data to determine a distance between the drill bit 14 and each passive listening device 12A, 12B.

[0023] One, two or more than two passive listening devices 12A, 12B may be used in various embodiments, and each passive listening device may comprise one or a plurality of receiving locations. Each passive listening device system may be connected to data receiving, recording and processing equipment 18 of types well known in the art for acoustic data recording and processing (which may be located proximate the drilling unit D by direct cabling, by wireless communication or other data communication known in the art.

[0024] Fig. 4 illustrates an acoustic signal detecting cable 15 placed on the ground or on the water bottom, where the signal detecting cable 15 contains spaced apart acoustic receivers 12 or uses so called distributed acoustic sensing. The cable 15 can be placed in a suitable pattern above and around the location where the wellbore WB is to be placed. The position of the drill bit 14 at any time may be determined using the acoustic travel time of noise from the drill bit 14 to each sensor 12 as explained above. The determined position of the drill bit may then be used to update the position determined from the magnetic/gravitational sensors in the drill string so as to reduce uncertainty of position.

[0025] In some embodiments, an active acoustic source 19 of any type known in the art may be disposed, for example, proximate the drill bit 14. At selected times, the active acoustic source 19 may be actuated, and a travel time of acoustic energy from the active acoustic source 19 to each acoustic receiver 12 may be determined. Both impulsive type source and vibratory type sources are known in the art for use in a wellbore and either or both types may be used in accordance with methods according to the present disclosure. Times of actuation of the acoustic energy source 19 may be pre-programmed into the data recording and processing equipment 18 so that detection of a pilot signal is not necessary. Source control devices usable in such applications are described, for example in U.S. Patent No., 5,555,220 issued to Minto.

[0026] Although only a few examples have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the examples. Accordingly, all such modifications are intended to be included within the scope of disclosure as defined in the following claims.

Claims

Claims What is claimed is:

1. A method for determining spatial position of a drill bit during drilling of a subsurface wellbore, comprising:

measuring acoustic signals generated by operating the drill bit to drill subsurface formations using an acoustic sensor proximate the drill bit;

measuring acoustic signals at a plurality of known, spaced apart locations on a land surface above the wellbore or on the bottom of a body of water above the wellbore;

determining a travel time of the acoustic signals from the drill bit to each known, spaced apart location using the measured drill bit signals and the measured signals at the plurality of locations; and

determining the spatial position of the drill bit using the determined travel times

2. The method of claim 1 wherein the determining travel time comprises cross-correlating the measured signals generated by the drill bit with the measured signals at each of the plurality of locations.

3. The method of claim 1 further comprising determining a distance between the drill bit and each of the plurality of known, spaced apart locations using the determined travel times and a velocity distribution of the subsurface proximate the wellbore.

4. The method of claim 3 wherein the velocity distribution is determined using surface reflection seismic.

5. The method of claim 1 further comprising calibrating a position of the drill bit determined using a geomagnetic and/or gravitational sensor package using the spatial position determined using the determined travel times.

6. The method of claim 1 wherein the measuring acoustic signals generated by operating the drill bit is performed using a pilot sensor disposed proximate the drill bit.