WO1993012319A1 - Systeme permettant de percer des trous de forage de maniere controlee selon un profil programme - Google Patents

Systeme permettant de percer des trous de forage de maniere controlee selon un profil programme Download PDF

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Publication number
WO1993012319A1
WO1993012319A1 PCT/US1991/009207 US9109207W WO9312319A1 WO 1993012319 A1 WO1993012319 A1 WO 1993012319A1 US 9109207 W US9109207 W US 9109207W WO 9312319 A1 WO9312319 A1 WO 9312319A1
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WO
WIPO (PCT)
Prior art keywords
depth
borehole
downhole
wheel
determining
Prior art date
Application number
PCT/US1991/009207
Other languages
English (en)
Inventor
Bob J. Patton
Original Assignee
Patton Bob J
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Patton Bob J filed Critical Patton Bob J
Priority to PCT/US1991/009207 priority Critical patent/WO1993012319A1/fr
Priority to AU13466/92A priority patent/AU1346692A/en
Publication of WO1993012319A1 publication Critical patent/WO1993012319A1/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B7/00—Special methods or apparatus for drilling
    • E21B7/04—Directional drilling
    • E21B7/06—Deflecting the direction of boreholes
    • E21B7/062—Deflecting the direction of boreholes the tool shaft rotating inside a non-rotating guide travelling with the shaft
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/02—Determining slope or direction
    • E21B47/022—Determining slope or direction of the borehole, e.g. using geomagnetism
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B7/00—Special methods or apparatus for drilling
    • E21B7/04—Directional drilling

Definitions

  • whipstock is basically a shaped body, generally iron or steel, placed in the existing borehole and oriented to deflect the drill into the desired direction.
  • BHA Bottom Hole Assembly
  • Multiple design changes are often required to get acceptable results.
  • the BHA is then changed to a design intended to drill straight ahead.
  • This whipstock method as crude, inaccurate and cumbersome as it is, served the drilling for many years but is used less today.
  • Another relatively old and useful method for changing and controlling the direction of a borehole is directional hydraulic jetting.
  • the bit jets are arranged to produce eroding jet streams in an off- vertical direction while the drill is not rotating and the jet streams are oriented in the desired drilling direction.
  • the drill is rotated to drill ahead a short distance. A series of such small steps can be used to turn to the desired direction. In soft formations, the jetting action is sufficient to cause drilling in the desired direction.
  • This method is subject to the formation properties and prone to much trial and error.
  • bent sub which is located above the drill motor.
  • the location of the bent sub is too far from the bit to allow significant rotation of the drill string without causing undue stresses and component fatigue. Consequently, the use of the bent sub restricts drilling operations to substantially constant TFO.
  • rate of curvature of the hole by this method is not dynamically controllable but rather is set by the BHA design and the drilling conditions. It is often necessary to make multiple trips in and out of the hole to change the BHA design until a satisfactory curvature is obtained.
  • the second version of the bend in the BHA is the so-called bent housing motor wherein there is a slight bend in the bottom section of the motor.
  • This small bend in the motor causes a curvature in the hole in the direction of the bend much as in the case of the bent sub.
  • the rate of curvature of the hole with constant TFO is a function of the bend and other BHA design factors along with borehole properties.
  • the rate of curvature of the bent housing method is not precisely controllable by design.
  • the bent housing motor due to its short bent section, can be rotated continuously or intermittently in the hole.
  • any value of average curvature between zero and the maximum value at constant TFO operation can be obtained.
  • This basic capability reduces the number of trips into and out of the hole thus saving time over the bent sub method.
  • the quality of the hole drilled by this method suffers from the interleaving of the multiple straight sections and excessive curvature sections caused by this method.
  • the offset stabilizer method often used with turbine type downhole motors is similar to the bent housing system in that it will turn when a constant TFO is held and will drill straight ahead when the drill pipe is rotated. The turn is caused by the offset stabilizer putting a side force on the bit.
  • the results are virtually identical with the bent housing motor system.
  • the means for providing information relating to said drilled path comprises means for obtaining information relating to the instantaneous depth of said drill bit within said borehole and means for obtaining information relating to the instantaneous direction of said drill bit within said formation and further comprising means for utilizing said depth information and said direction information to provide said profile of the drilled path.
  • FIG. 1 is a conceptual view of a drilling system employing the automated drilling system of the present invention.
  • Fig. 3 a-b are illustrations of controlling the direction of penetration of the bit by adding a shear force and changing the direction of the bit.
  • Fig. 4 is an illustration of a composite Directional Rotary Drilling system in the borehole.
  • Fig. 5 a-c is an illustration of a controlled offset stabilizer using a single, non-rotating, eccentric offset with controllable direction.
  • Fig. 6 a-e is an illustration of a controlled offset stabilizer using a non- rotating section comprised of a symmetrical vane element and two eccentric elements which are actively positioned to control the direction and value of eccentricity.
  • Fig. 7 a-d is an illustration of a controlled offset stabilizer which uses hydraulics to control the position of the non-rotating multiple vanes resulting in full control of the magnitude and direction of the offset , size or caliper of the vanes, and force on the vanes.
  • Fig. 9 is an illustration of a modification to the surface of a controlled vane which insures non-rotation of the vane assembly.
  • Fig. 10 a-b is an illustration of a magnetic marker assembly used to magnetically mark the borehole wall at measured depth intervals thus providing a method of accurate downhole incremental depth measurement.
  • Fig. 11 a-b is an illustration demonstrating the principles of operation of the magnetic marker downhole incremental depth measuring method.
  • Fig. 12 is an illustration of a depth measuring wheel which provides a method of measuring incremental downhole depth accurately and with high resolution.
  • Fig. 16 is an illustration of the adaptive directional control system.
  • Fig. 17 is an illustration of the corrective connect plan method.
  • Fig. 1 illustrates an overview of the automatic directional rotary drilling system employing the non-rotating controllable stabilizers of the present invention
  • a downhole drilling system 10 which can be automatically controlled from a remote location, such as an operator's office 12.
  • the system is capable of automatically rotary drilling a high quality borehole accurately along a three- dimensional well profile plan illustrated generally by reference number 14.
  • the plan loaded into the system at the surface, to control the system from spud point to target 16 without any additional information, instructions or control being necessary.
  • the automatic self-guiding rotary drilling assembly 10 is equipped with non- rotating controlled stabilizers 22 to affect the directional control, as will be discussed in greater detail below.
  • the drilling assembly also contains directional survey, drilling, and formation sensors 26 and a wire retrievable and replaceable package 24.
  • the package 24 allows larger quantities of data to be exchanged between the surface and downhole than the real time system can support.
  • the 2- way real time communications 18 is accomplished by an upward communication channel 15, commonly called MWD, and two downward communications channels 17, controlled rotary speed 21, and 19, controlled mud pump speed 23. Both the upward channel and the downward channels are well known in the an of measurements-while-drilling, MWD.
  • U.S. Patent No. 3,789,355 teaches a upward communications system and U.S. Patent No. 3,800,277 teaches downward channels.
  • the weight and flex of collars can be combined with appropriately sized and spaced stabilizers to add either a "high-side” or "low-side” force.
  • a bent sub may produce a perpendicular force in almost any angle of rotation around the borehole axis depending on its geometrical relationship to the existing borehole and its orientation.
  • the net penetration-rate vector is the result of many factors including: 1.) The direction of the bit and the directional cutting preferences of the bit (the bit anisotropy) 2.) The force vector (direction and magnitude) 3.) Formation effects, both formation anisotropies and beddin g-plane to bit-face interactions 4.) Others, such as the cleaning efficiency due to the mud flow rate, etc.
  • the penetration rate will be proportional to a bit anisotropy tensor times the force vector.
  • the direction of the penetration rate 38 is not in the direction of the bit axis 32, nor in the direction of the force 40, but will lie in the same plane 42 that they define; for ⁇ 1, it will lie between them. In the general case where formation effects are included, it may not be coplanar.
  • a tangent line 44 to the existing borehole 46 is not necessarily in the same direction as any of these.
  • the primary advantage of the present invention is to provide complete directional control while using the conventional rotary drilling method and without restrictions to the normal high efficiency of the rotary method. High quality straight and directional drilling is accomplished without trips to change equipment for directional purposes.
  • Fig. 4 is an illustration of the directional rotary drilling system 10' in a curved borehole 46'. Above the dashed line standard components 1 of a rotary drilling system are shown including drill collars 62 and stabilizer 64.
  • the special directional system components are shown below the dashed line and are generally non-magnetic to avoid magnetic interference with the directional sensors.
  • the upper portion above compliant sub 66 is basically an enhanced MWD system which is divided into two sections, 10a and 10b.
  • the uppermost section 10a composed of stored data 68, MWD transmitter 70, and a power source 72 is retrievable by wire line without removing the drill string. The retrieval process may be carried out to obtain high quality data, repair or replace the transmitter, or repair or replace the power source.
  • the lower section 10b, including the central system 74, is not retrievable.
  • the central system 74 includes full data acquisition and processing capabilities, communications management, data storage such as the well plan to be drilled, processing algorithms, and data sensors.
  • a power and data bus 76 connects between all downhole components.
  • a necessary sensor is a full directional survey package which may also serve as magnetic sensors 78 to activate the magnetic marker 80.
  • the distance L between the magnetic sensors 78 and the marker 80 is accurately known to provide accurate downhole incremental depth measurements.
  • the compliant sub 66 and below provides the mechanical control of direction of penetration of the drill.
  • the compliant sub 66 which is preferably instrumented to measure the weight-on-bit (WOB) torque-on-bit (TORQ) and bending allows making the direction of the bit to be different than the borehole or drill string.
  • the controllable stabilizers 82 and 84 are used primarily to control the angle of the bit and/or the shear force on the bit by controlling the adjustable eccentricity 81, either of which can control the direction of drilling of the bit 30.
  • the near-bit sensors 86 may include formation logs such as gamma-ray, resistivity, density, and porosity. Other desirable sensors include mud resistivity, temperatures and mud pressures inside the collars and in the annulus.
  • the depth wheel 88 and marker 80 provide downhole incremental depth important in calculating the drilled well profile.
  • controllable means that elements of the stabilizer can be varied such as to affect the direction of penetration of the bit, principally through modifying the direction of the bit and/or the shear force on the bit.
  • curvature is the degree of bending or turning of the borehole and usually has the units of degrees/100 feet or degrees/10 meters.
  • Tool face orientation is the clockwise angle from the high side reference in the ahead, high and right downhole coordinate system, Fig.2.
  • the degree of curvature and its tool face orientation are functions of and can be controlled by the degree of eccentricity of the rotating drill bit in the borehole and its tool face orientation.
  • the non-rotating eccentric elements 92, 100, and 98 are a single structure which is positioned by latch 114. This is accomplished by activation of solenoid 116 driving the latch 114 into recess 118 where it rotates until it engages the eccentric driver 118a protruding into recess 118 and rotates the eccentric to the desired orientation when the solenoid power is terminated and spring 120 withdraws latch 114 leaving the eccentric in the desired orientation.
  • the driver 118a is affixed to the eccentric in a precisely indexed position such as the point of maximum eccentricity.
  • the solenoid is powered by power supply 122 which is controlled by the bus interface 124.
  • Bus 76' supplies power and control signals.
  • Connector 128 connects the bus 76' to the bus in other sections of the system.
  • a special tool joint 130 connects the various modules of the system.
  • Articulated vane 132 is loaded by springs 134 forcing cutters 136 to cut small grooves into the formation thus preventing rotation of the system. This antirotation method is further described below and shown in Fig. 9.
  • the spring loading allows the cutters to retract during the positioning process.
  • the correct orienting information supplied in the following manner.
  • the directional drilling algorithms in the central processor calculate the desired Tool Face Orientation (TFO) for the eccentric to drill in the desired direction.
  • the directional sensor package measures the TFO of the rotating system continuously and, via the bus, signals the solenoid interface 124 at the exact moment to withdraw the latch 120 leaving the eccentric section 98 at the desired TFO. Because the eccentric does not rotate, this process of orienting the eccentric need be done only infrequently.
  • Figs.5d-e illustrates a controllable stabilizer utilizing a single eccentric with separately controllable tool face orientation and eccentricity.
  • Tool face orientation control is the same as described above and shown in Fig. 5a-c.
  • the degree of eccentricity is controlled from zero to a maximum value by means of movable vane element 206 contained in the vane cavity 204 within the larger portion 98a of the non-rotating element 92a.
  • the vane cavity 204 is pressurized by hydraulic fluid supplied by compensator 104 in Fig. 5a via inlet 105 and is isolated from the annular drilling mud by seals 212.
  • Power and data bus 76a which is an extension of bus 76' in Fig.
  • Interface 5a supplies power and control signals to interface 85 via the slip ring connector 75 between rotating element 90 and the non-rotating element 92a.
  • Interface 85 receives the movable vane 206 extension position from position sensor 210 via connection 87 and relays it to the central processor via bus 76a.
  • the central processor calculates any desired change in the movable vane 206 position and relays the necessary information back to the interface 85 via bus 76a.
  • Interface 85 then energizes the vane mover 91 via connection 89 causing the vane 206 to move to the desired position. This process of monitoring and adjusting the movable vane position to the desired value is continuous.
  • This single eccentric non-rotating stabilizer with controllable eccentricity and tool face orientation can effectively control the three-dimensional path of the borehole.
  • Figs. 6a-e illustrate a dual eccentric stabilizer composed of a rotating element 90' and three non-rotating elements: a concentric outside vane assembly 92' which is supported by the borehole 46 in a non-rotating fashion, an outer eccentric 152, and an inner eccentric 15G which supports the rotating element 90' through bearings 94'.
  • the volume around the eccentrics and bearings is pressurized with hydraulic fluid supplied by pressure compensator 104' which is supplied with mud pressure through channel 138 or 108' as controlled by valves 142.
  • Compression spring 110' in conjunction with piston 106' creates a hydraulic fluid pressure above the inside mud or annulus mud pressure chosen by valves 142.
  • the seals 112' isolate the hydraulic fluid and the mud.
  • the eccentricity of the rotating element 90' with respect the the borehole 46 is controlled solely by the orientations of the two eccentric elements 150 and 152.
  • the orientation of outside vane element 92' has no effect on the eccentricity because it is concentric within itself.
  • This vane element 92' is held in a non-rotating position within the borehole 46 by multiple vanes and anti-rotation devices 136' described below and shown in Fig. 9.
  • the outer eccentric 152 is oriented to any desired TFO by operation of gear 156 which is affixed to the outside vane element 92', as shown in Fig. 6a.
  • Gear 156 meshes with ring gear 160 teeth not shown which is affixed to and completely around outer eccentric 152.
  • the inner eccentric 150 may be oriented to any TFO by operation of gear 162 which is affixed to eccentric 150.
  • Gear 162 meshes with ring gear 164, teeth not shown, which is affixed to and completely around the inside of outer eccentric 152.
  • the information for the number of pulses to be supplied is input to the interface 178 through bus 76" and bus connector 128' from the central processor.
  • gear 162 is driven by gear reduction 180 and electric stepping motor 182.
  • Driving pulses for motor 182 are supplied by electrical leads through slip ring 172 from the bus interface 178.
  • the number of pulses is supplied by the central processor through the bus system.
  • TFO the effective orientation of the net eccentricity
  • TFO i the Tool Face Orientation of the inner eccentric
  • N o number of pulses sent to outer drive motor
  • N i the number of pulses sent to the inner drive motor
  • the starting point for this discussion is that the central processor has already determined the desired TFO o and TFO i values such that the remaining task is to set these values into the controlled stabilizer.
  • Magnetic detectors 184 and 186 mounted in the rotating element 90' each produce a pulse as they are rotated by the magnets 188 and 190 mounted in the outer eccentric 152 and the inner eccentric 150 at the orientation of maximum eccentricity of each eccentric.
  • the occurrence of each pulse is transmitted by the bus interface 178 through the bus 76" to the central processor where a comparison is made with the TFO information also coming in over the bus from the directional sensor package.
  • the actual existing TFO i and TFO o are thus determined.
  • the central processor compares these actual TFO values with the desired values and calculates N i and N o , the number of stepper motor pulses needed to correct the TFOs to desired values. These values of N i and N o are transmitted over the bus system to the bus interface 178 which then sends N i and N o to stepper motors 182 and 170, respectively. The motors then orient the eccentrics to their exact desired orientation as described above.
  • the magnetic detectors 184 and 186 continuously monitor the TFOs. No further orientation action is normally required until the desired values of TFOs are changed or after long drilling has resulted in some creep in orientation of the nonrotating vane element 92' has occurred. Fig.
  • FIG. 6d and 6e illustrate setting the TFOs to desired values from initial values 189 of zero illustrated in Fig. 6a-c.
  • Fig. 6d which illustrates the orienting magnetic pulses 191 and 193 has a linear TFO scale 187 from 0 to 360 degrees and
  • Fig. 6e is the high 34 and right 36 plane of the high, right, ahead coordinate system described in Fig. 2 wherein TFO is measured clockwise from high which is zero.
  • the outer eccentric is rotated to a TFO o desired 195 of 80 degrees and the inner eccentric is rotated to a TFO i desired 197 of 200 degrees.
  • Figs. 7a-d illustrate a multi-vane stabilizer with independent hydraulic control of each vane. This method provides full control of the following parameters: (1.) magnitude of eccentricity, (2.) direction of the eccentricity of the rotating element with respect the borehole, (3.) setting of the size of the stabilizer to fit tightly in the borehole, (4.) recording of a precision caliper log as drilled, and (5.) direct control of the shear force on the bit and, alternately, the shear force to weight-on-bit ratio.
  • Figs. 7a-d includes a compliant sub element 66' along with allied strain measuring sensors 198 and 200 which will be discussed separately below.
  • the non-rotating element 92" contains in chambers 204a-d movable vanes 206a-d hydraulically controlled to individually press against the borehole 46 causing element 92" to be positioned eccentrically within the borehole as desired.
  • Rotating element 90" is held in the same eccentric position as element 92" by bearings 94".
  • Each vane 206a-d is equipped with a position sensor 210a-d which enables exact individual placement of each vane. Seals 212a-d ensure pressure tight compartments 214a-d between vanes 206a-d and vane cavities 204a-d. Hydraulic lines 218a-d supply individually controlled hydraulic fluid to the compartments 214a-d.
  • Tension springs 216a-d retract the vanes 206a-d to minimum extension which is within the cavities 204a-d when the hydraulic pressure in compartments 214a-d is minimized providing protection during tripping.
  • the volume 236 between elements 92" and 90" is filled with pressurized hydraulic fluid supplied through duct 220 and sealed in by seals 112'. Incremental depth is provided by a depth wheel inse ⁇ 202 into vane 206a. Magnetic detector 221 detects the depth indicating magnets in wheel 88'. Depth measurement is described separately, below.
  • Magnetic detector 226 detects the passing of position indexed magnet 228 providing precise orientation (TFO) of the non-rotating element 92".
  • Pressure sensors 230 and 232 provide inside mud pressure 96 and internal compartment 236 pressure respectively, and are connected to the bus system via interface 201.
  • Pressure sensor 234 provides the annulus mud pressure and is connected to the bus system via data acquisition system 282 and bus interface 280.
  • Strain sensor 200 provides torque on the drill bit.
  • Strain sensor 198 provides both weight-on-bit and bending which is convertible to both bend angle and shear force on the drill bit.
  • Sensor 238 provides mud resistivity data.
  • Power and data bus 76" is connected to other modules through connector 128" and between the rotating elt nent 90" and non-rotating element 92" by interface 242 which can be common slip rings.
  • interface 242 can be common slip rings.
  • Network 244 distributes electrical and hydraulic lines between areas of the module. Hydraulic arid electronic equipment are housed in compartments 246. Sealed and- pressure proof covers 248 provide environmental protection for the equipment.
  • Fig.7d shows more detail of the servo controlled hydraulic operations.
  • a source of pressure compensated hydraulic fluid 250 consists of annulus mud 258 and spring 110" acting on sealed piston 106" produces hydraulic fluid 104" pressure compensated slightly above the annulus mud pressure. This higher fluid pressure increases seal life by reducing the entrance of mud abrasives into the seals.
  • Conduit 266 supplies hydraulic fluid to unit 252 which consists of an electrically driven hydraulic pump 268 and a high pressure accumulator 270.
  • Conduit 272 supplies high pressure hydraulic fluid to hydraulic control unit 254 which meters the hydraulic fluid individually to the conduits 220 and 218a-d.
  • Conduit 276 returns surplus hydraulic fluid to the input of pump 268.
  • Unit 256 is an electronic processor which contains three sections; a bus interface unit 280 which interfaces via bus 76" with the central processor, a local data acquisition and processing unit, and a servo controller unit 284.
  • a bundle of conductors 286 connects servo controller 284 to the hydraulic controls.
  • Conductor 288 supplies power to the hydraulic pump motor.
  • a bundle of conductors 290 from the data acquisition section 282 accesses the sensors as shown by the conductor numbers. Pressure sensor 230 and 232 data are received through bus 76".
  • Shear force is dynamically controlled to be compatible with weight-on-bit controlled from surface.
  • Fig. 8 shows a cross section through a mechanical vane along the axis of the borehole the same as in Fig. 7a of the hydraulic system.
  • Movable vane 300 is sealed to vane cavity 204' by seal 212' identical to the hydraulic system.
  • Cavity 204' is filled with hydraulic fluid via duct 306 which is pressure compensated slightly above the pressure of the annulus mud for greater seal life and minimum interference with mechanical operation.
  • Heavy duty screws 308 have mating threads 310 with the vane 300 and are held with virtually no translation possible by clamps 312.
  • the screws 308 are free to rotate about an axis parallel with threads 310 and are induced to do so by rotation of worm gear 314 which engages with ring gear 316 which is integral with screw 308.
  • Gear 314 is rotated by means of drive train 318 when stepper motor 320 rotates shaft 322.
  • the drive train is arranged such that gears 308 turn in the same direction when motor 320 rotates shaft 322.
  • the mechanical vane is operated by information supplied from the central processor via bus 76'" and bus interface 324.
  • the central processor has stored in its memory the factor relating the number of pulses required to move the vane an exact distance.
  • the central processor also keeps track of where the vane is at all times so that to obtain any other position the central processor need only calculate the required sign, vane in or out, and number of pulses and transmit them over the bus 76'" to interface 324.
  • the interface then sequences that number of power pulses with proper sign and power level through lead 327 to the stepper motor 320.
  • the vane extension force is a function of pulse power level used; maximum power is used when power level is not specified.
  • step 2 the caliper process used the following operations: (a.) interface 324 issues a preset small number of full power retraction pulses insuring vane size less than borehole size, (b.) interface 324 issues a continuous string of the specified power level extension pulses until sensor 326 reaches a constant value when caliper process is finished.)
  • (2.) Central processor calculates shear force to weight-on-bit ratio required to drill desired curvature using stored bit anisotropy tensor and any available formation anisotropy information. Further calculate estimated position required and issue pulse data to interface 324 via bus 76'".
  • Interface 324 issue prescribed pulses to vane motors.
  • central processor monitors shear force and weight-on-bit sensors and issues incremental correction pulses to interface 324 which are relayed on the vane motors in such a manner as to maintain the prescribed shear force to weight-on-bit ratio and direction. Preparation to trip out of hole.
  • Central processor issue trip command
  • Interface 324 issue continuous string of full power retraction pulses until position sensors 326 indicate full retraction of vanes.
  • Fig. 9 is an illustration of an improvement to the face of the vane in contact with the borehole which provides positive control of rotation.
  • Reference numeral 330 is the downward edge and 332 is the face which presses against the borehole wall.
  • Line 334 on the face of the vane 332 is parallel with the axis of the borehole.
  • Knives 136'" serve two basic functions: (1.) to cut a groove in the borehole face and (2.) follow in the groove.
  • the knives are mounted on the face of the vane substantially parallel with the axis of the borehole as shown by the angle 338 between line 334 and a line 340 representing the axis of the knife.
  • the knives should follow precisely in the groove cut by the leading edge 342 in which case the vane will rotate in proportion to angle 338.
  • angle 338 is zero and the torque is zero, the vane should not rotate.
  • a small angle 338 may be used to counter any creeping tendency.
  • the actual construction of the knives can take many forms. A very simple form is to braze onto the vane face a long thin bar of tungsten carbide with a triangular cross section.
  • the leading edge 342 of such a knife could be faced with a polycrystalline diamond to improve the cutting and wear characteristics.
  • the size of the knife could be progressively increased from a small section 344 to a maximum in a series of steps where each step in size is faced with a special cutter such as the polycrystalline diamond.
  • Directional survey data and the borehole depth are necessary to the process of calculating the well profile.
  • the directional survey data are taken downhole against a clock and telemetered to the surface where the surface depth is recorded against the clock.
  • the two clock referenced measurements of depth and directional data are combined to produce depth referenced directional survey data.
  • the hole profile is calculated downhole; consequently, both directional survey data and corresponding depth are required downhole at the time of well profile calculation.
  • ID - integral downhole measured incremental depth since last MD s download Three methods of obtaining MD are described below.
  • Fig.4 shows magnetic marker assembly 80 spaced at a precisely measured distance L from magnetic sensors located uphole.
  • FIG. 10a-b illustrates the details of the marker 80.
  • a formation magnetizer 350 is built into the marker assembly 80 which also contains a power and data bus 76"".
  • Interface 354 receives information and power from the bus 76"" and manages the magnetizer driver 356 which supplies current to coil 358.
  • Magnetizer 350 is constructed of high permeability magnetic material. Current flow through coil 358 causes the magnetizer 350 to be magnetized with magnetic poles at its ends which have an intensity dependent on the value of the current.
  • the downhole mud flow is through channel 96 which diverts from the center around the magnetizer.
  • Fig. 11a illustrates the magnetic marking process and how precise depth increments are obtained.
  • Reference numeral 370 represents the location of the magnetizer 350 in the downhole system 10.
  • Mark 372 was created in the formation by a current pulse through the magnetizer when the system was in the position shown in the upper portion of the illustration and mark 374 was created later when the system had advanced an incremental distance 376.
  • the incremental distance is shown as L in Fig. 4 and 3d in Fig. 13a.
  • Precise spacing of the distance L between the marks is accomplished by using the magnetic sensors 378, spaced a distance L from the marker, to detect the passing of mark 372 and immediately signaling via the central processor, bus 76"" and interface 354 of Fig. 10a.
  • a demagnetizing wave 382 follows the marker which serves a magnetic cleaning function. This demagnetizing wave has an initial current magnitude substantially smaller than the marker pulse thus leaving the formation magnetized while demagnetizing the much lower coercivity magnetic materials of the marker assembly and any surrounding DRD system components.
  • the magnetic cleaning wave 382 has a decaying amplitude function as characteristic of demagnetizing systems. The incremental depth resolution of this marker is limited to about one foot to avoid overlapping of the marks.
  • the depth wheel system shown in Fig. 12 is, in one embodiment, an insert 202' which fits into a vane of a non-rotating stabilizer such as shown by 202' in Fig. 7a.
  • the depth wheel 88" in Fig. 12 is completely enclosed within insert 202' except for a small area through which the depth wheel protrudes to contact the formation 46 at point 394.
  • the depth wheel is pressed firmly against the borehole by means of spring 396 through bearing 398 and the axle 400 of depth wheel 88".
  • Depth wheel 88" is constrained to move only in a direction perpendicular to the borehole by caging mechanism 402.
  • the rim 404 of the depth wheel 88" which contacts the borehole 46 is constructed to roll on the borehole surface with a constant rolling circumference; that is, without variable slippage.
  • the surface consists of very hard, fine, sharp teeth which run parallel with the wheel axis and have a curvature which matches the borehole. These teeth embed slightly into the borehole providing a substantially constant rolling circumference of the depth wheel.
  • Another means of accomplishing a constant rolling circumference is a sharp abrasive particle coating on rim 404.
  • Depth changes are measured by detecting the passing of magnets 406 by the detector 221'. Electrical leads 410 connects detector 221' to suitable circuitry or bus interface. Detector 221' is composed of multiple magnetic detectors arranged to unambiguously detect depth changes in either deeper or shallower directions. One method for such unambiguous detection is shown in U.S. patents 4,114,435 and 4,156,467 which contain a method of encoding borehole depth at the surface location of the well.
  • the magnets 406 are an even number of magnets closely spaced with alternating pole signs. Magnet spacing smaller than one-half inch can be reliably detected providing a depth resolution of one-half inch or less.
  • the depth wheel insert 202' is sealed into the stabilizer vane 412 by means of seal 414 thus maintaining isolation of the interior 416 of vane 412.
  • FIG. 13a-c illustrates the relationship of the three components of downhole depth; surface depth download and two sources of incremental downhole depth, namely, magnetic mark pulses and depth wheel pulses.
  • the surface depth 420 is downloaded at time 422 into surface depth register 424 as indicated by the download pulse 426.
  • either the magnetic mark pulses 576, 578 ... or the depth wheel pulses 428, 430 ... are the source of the 3d pulses 432. 434 is the
  • the output register of summation circuit 440 increments by a depth amount plus or minus 434 when a pulse 432 is received via 442 in accordance with the sign of the pulse received.
  • Summation circuit 440 output register is reset to zero via 446 each time the surface depth is downloaded; consequently, the current value of the incremental depth since the last surface depth download is contained in the summation circuit 440 output register.
  • Adder 448 sums the value of the last downloaded surface depth 424 received via 450 and the value of the incremental depth since the last download of surface depth 440 received via 452 to obtain the value of the current depth which is sent to the current depth register 454 via 456.
  • the current depth of the drill bit is contained in register 454 at all times.
  • Maximum value circuit 456 extracts the maximum value of the current depth received via 456 which is routed to well depth register 460 as the Total Well Depth known as TD.
  • Adder 462 accumulates incremental time by summing high speed pulses received from clock 464. pulses sent via 466 cause adder 462 to output the incremental time between pulses, 3 , to divider 468 and reset to zero. pulses received via
  • divider 468 causes divider 468 to divide the value of received from 434 via 470 and output the ratio, via 472 to the ROP register 474 as the Rate-Of-Penetration,
  • ROP of the drill. This ROP is for the smallest increment of depth, just completed.
  • the depth interval pulses 494 are routed via 496 to ROP filter 480.
  • ROP filter 480 upon receiving a depth interval pulse 494, divides the value of summed ROP received via 482 by the value of the depth interval D received via 492 to produce an average value of ROP over the depth interval D.
  • the average ROP is output via 498 to the D interval average ROP register 500 and a pulse is sent via 502 which resets ROP adder 478 to zero.
  • the specific technique of averaging ROP discussed in not intended to limit the method but merely illustrate the method.
  • Fig. 13c illustrates a method of downhole calibration, or verification, of a downhole incremental depth measuring system by another.
  • the specific example illustrated is the calibration of the high resolution depth wheel shown in Fig. 12 by the high accuracy magnetic marker system shown in Fig. 10a-b and Fig. 11a-b.
  • Depth wheel pulses 510 examples shown in Fig. 13a by 428 and 430, are counted by counter 512.
  • Magnetic mark pulses 514 examples shown in Fig. 13a by 576 and 578, cause counter 512 to forward the current pulse count to pulse count register 520 and to reset to zero.
  • Register 522 stores the accurately known distance L between the magnetic marker and the magnetic mark sensor shown by 436 in Fig. 13a and illustrated in Fig. 4.
  • the generator 524 calculates the distance between pulses, by dividing the distance L received from register 522
  • generator 524 forwards the value of to the register 526.
  • the value of in register 526 is one source for the value of used in Fig. 13a 434.
  • the compliant sub is a specially engineered section of the drill collar with generally reduced cross sectional area to provide desired bending (change of direction) and measurement of mechanical strains. Measurement of the mechanical strains, combined with knowledge of the parameters of the system, allows the calculation of critical directional drilling parameters: 1.) the ahead force on the bit (weight-on-the-bit), 2.) the shear (side) force on the bit, 3.) the total angle of bend and its direction, 4.) the relative penetration rate of the bit ahead and to the side (curvature of hole) and the direction (of curvature), and 5.) the rotary torque on the bit.
  • the compliant sub may be engineered for optimal performance at any one or combination of these measurements.
  • the compliant sub may optionally be combined with other elements such as a non-rotating stabilizer as is shown in Fig. 7a.
  • Fig. 14a-e illustrates basic parameters and relations of the compliant sub, strain measurement, and calculation of the drilling parameters.
  • Fig. 14a illustrates the mechanical layout of a borehole 46 containing rotating drill collar 11' with drill bit 30' attached. Cutout A exposes a cross sectional view of a compliant sub 66' of length 550, Lc, inner diameter 552, 2r i , and outer diameter 554 2r o . Drilling mud flows down through the channel 96 in the rotating compliant sub and collar 11'.
  • a non-rotating controllable stabilizer 92"" is used in conjunction with the compliant sub to provide eccentric offset of the sub 66' in the borehole 46.
  • Strain sensor pair 562a and 562b are mounted parallel to the axis on the indexed high side and low side (180); respectively, of the compliant sub and measure the two surface axial tensional strains.
  • strain sensor pair 564a and 564b mounted at 45 degrees to the axis, measure the rotary torques.
  • the distance 566 between the compliant sub 66' and the bit 30', Lb, is a design parameter.
  • the total force on the bit is measured and specified with three variables: 1.) the force along the axis of the bit 568, F w , 2.) the shear (perpendicular to axis) force on the bit 570, F s , and 3.) the angle of the shear force 572, TFO B , in its high-right plane shown in Fig. 14b, d.
  • the axis of the bit (down) forms the ahead direction of the ahead, high, and right coordinate system used here.
  • Fig. 14a is in the high, ahead plane
  • Fig. 14b is in the high, right plane. Looking at Fig. 14b is equivalent to looking directly down the axis of the drill.
  • TFO Tool Face Orientation
  • the TFO domain illustrated in Fig. 14c, and used in Fig. 14d and e, is generated in the local processor by means of timing pulse 580a transmitted from the central processor via the bus system described in discussion of Fig. 4, the DRD System.
  • FIG. 14c illustrates this clock system wherein a timing pulse 580a initiates the time scale 582 and the next revolution timing pulse 580a' terminates the scale.
  • the scale is convened to a TFO scale 584 by dividing it linearly from 0 to 360 degrees. This TFO domain is used in the local processor to describe the high, right plane angles and phase relationships.
  • the TFO of the non-rotating element 92"" is determined by displaying the pulse 586a generated by the passing of the rotating element 90'" high side reference magnet 580 by the magnetic detector 586 mounted at its reference location in the non-rotating element 92"".
  • the non-rotating element 92"" TFO 574, TFO n-r of approximately 108 degrees is shown in both Fig. 14b and c.
  • the local processor has this non-rotating controlled stabilizer 92"" TFO information which is necessary to controlling the eccentric parameters of the stabilizer previously described in conjunction with the various types of stabilizers.
  • the strain sensors 562ab and 564ab are mounted on the rotating element compliant sub 66' with the a sensors aligned with the high side and the b sensors aligned at 180 degrees to the high side providing a known phase relationship with the high side.
  • the output of tensional strain sensors 562a, mounted at high side, and 562b, mounted at 180 degrees from high side, are shown in Fig. 14d.
  • the output of torque strain sensors 564a, mounted at high side, and 564b, mounted at 180 degrees from high side, are shown in Fig. 14e. Note again that all strain signals are detected in the TFO domain.
  • the bit shear force 570, F s , its TFO 572, TFO B , and the causative eccentricity 575 E are shown.
  • Fig. 14d illustrates the outputs and relations for the tension-compression sensors 562a and b. Both weight-on-bit and bending forces cause output from these sensors. True weight-on-bit causes a uniform output in both the a and b sensors which is not a function of TFO.
  • Both a and b sensors have a constant and equal output proportional to weight-on-bit.
  • a simple bend of the compliant sub causes a compressional strain in the compliant sub on the concave side of the bend and an equal tensional strain on the convex side of the bend.
  • Rotation of the compliant sub while keeping the bend constant in space produces the sensor outputs 562a and 562b shown in Fig. 14d.
  • the strain due to weight-on-bit 590, S w is obtained by adding the sensor outputs 562a and 562b.
  • the strain due to bending 592 is obtained by subtracting 562b from 562a varies with TFO and has a positive and negative peak value 594, S B .
  • the negative strain peak TFO 596, TFO B is the direction of the shear force 570, F s .
  • the three measured tension sensor parameters S w, S B , and TFO B are used with the values of the geometrical factors, material properties, and constants to calculate the drilling parameters: (1.) ahead force on bit (weight), F w , (2.) shear force on bit, F s , and its direction, TFO B , (3.) total bend angle of the compliant sub, ⁇ B , and its direction, TFO B + 180, and a hole curvature factor, C, and its direction, TFO B .
  • F w S w Y ⁇ (10)
  • F s S B Y ⁇ /L b , ZTFO B (11)
  • ⁇ B S B L c /r o , ZTFO B + 180
  • C G F s /A b F w , ZTFO B (13)
  • Fig. 14e illustrates torque sensor outputs 564a and 564b. These outputs have component signals due to the weight-on-bit and bending as well as torque. The effect of weight is removed by subtracting 564b from 564a giving 564a-564b. This subtracted signal 564a-564b is averaged over one revolution of the compliant sub to yield the constant value of torque strain 598, S T , in Fig. 14e.
  • the equation used to convert the torque strain, S T , into the the rotary torque, T is:
  • Fig. 14a is a suitable assembly to utilize the shear force method of directional drilling wherein 600 is either a non-rotating or standard centralizing stabilizer placed at a distance 555, L, from the bit.
  • the eccentricity 575, E, in Fig. 14b is the causative agent for and is propo ⁇ ional to F s .
  • the parametric control equation is:
  • Controlled F s /F w ratio mode This is a preferred mode which requires the following elements: 1.) controllable eccentricity, 2.) controllable TFO of eccentricity, 3.) strain measurements and calculation of F w , F s , and TFO B , and 4.) a drilling assembly designed to use the shear force method only. (The desired hole curvature and direction are known from independent consideration not considered a pan of this mode.) The appropriate values of F s /F w , and TFO B are calculated to drill the desired curvature and direction. The measured values of F w , F s , and TFO B are continuously monitored and adjusted to produce the desired calculated values of F s /F w , and TFO B by controlling the eccentricity and its TFO.
  • F w is controlled at the surface by the driller and varies significantly in time.
  • F s and TFO B are controlled downhole via eccentricity and its direction.
  • the salient aspect of this mode is that one set of parameters, eccentricity and its direction, is manipulated to dynamically maintain another set of parameters, F s /F w and TFO B , at desired values.
  • This mode requires a minimum of a non-rotating stabilizer with excessive eccentric offset which has controllable TFO such as in Fig. 5a-c.
  • the desired hole curvature and direction are given.
  • the generic mode is to drill multiple short segments of the hole which have excessive curvature and the TFO of the segments are distributed such that the interval over a group of successive segments has an average curvature and TFO equal to the desired values.
  • a specific and simple variant of this mode is where the TFO distribution has only two values; the desired TFO and the desired TFO plus 180 degrees.
  • Controlled Eccentricity and TFO This mode requires a non-rotating stabilizer with independently controllable eccentricity and TFO such as in Fig. 6a-e.
  • the desired hole curvature and direction are given. Calculate the eccentricity required by the particular tool parametrics to drill the desired curvature. Set the stabilizer to this calculated eccentricity in the desired TFO direction.
  • Controlled Vane Force and TFO This mode requires a non-rotating stabilizer with independently adjustable vanes such as in Fig. 7a-d. The desired hole curvature and direction are given. Calculate the required individual vane force, or position required to produce that force, as a function of vane TFO required to drill the desired curvature and direction. If the vanes are hydraulically operated either the vane forces or the vane positions are set. If the vanes are mechanically operated the vane positions are set.
  • the adaptive mode is a supplementary mode and can be used in conjunction with any of the above deterministic modes to reduce any errors in the analytical models and correct for unaccounted for factors such as formation drillability anisotropy and can be used with any control mechanism.
  • the basic process is to compare measured curvature and TFO of the actual drilled hole with the planned or desired values of curvature and TFO and use any residual differences to modify the control parameters in such a manner as to offset the residual error.
  • This adaptive mode can be reiterated on each successive section drilled.
  • the salient property of the adaptive mode is the correction for any error observed on the last section drilled in the section ahead.
  • Predictive mode The predictive mode is the inclusion into the control settings changes to offset the effects of changing drilling variables at the depths they are predicted to occur. Such predictable changes include changes in drillability anisotropy or crossing of a fault predicted from lithological information such as well logs.
  • the predictive mode is a adjunct to the deterministic modes.
  • the corrective mode is a process of drilling to offset any deviation of the drilled well profile from the planned well profile.
  • An effective corrective mode is to make a new planned well profile which connects the current drilled well profile to a deeper point on the original planned well profile or other more desirable deeper point.
  • a profile of the well as drilled is calculated downhole in the central processor as directional surveys are taken.
  • Three things are needed to calculate the drilled well profile: (1.) directional survey data, (2.) the measured depths at which the directional surveys are taken, and (3.) a suitable algorithm.
  • Directional survey sensors are state-of-the-art and part of the downhole data acquisition system. Multiple methods and means for acquiring measured depth downhole are a part of this invention described earlier.
  • Several good algorithms for calculating the well profile are state-of-the-art. One or more of these is stored in the processing system.
  • the accuracy of the well profile is enhanced by frequent directional survey data which is available on an essentially continuous basis.
  • the well profile must be calculated with sequentially deeper data and can be current to the last data in.
  • a desired well plan profile to be drilled is stored in the downhole central processor system.
  • This stored well plan profile may be updated by either of three methods during the course of drilling the well: (1.) the stored plan may be updated at the surface whenever the downhole system is tripped out to the surface, (2.) Surface-to-downhole data communication can update the well plan, and (3.) the well plan may be updated or modified by the downhole central processor.
  • An example of downhole modification of the well plan is the corrective mode described earlier. In general, modifications to the well plan are small and are for the purpose of minimizing dog leg of the hole and improving the accuracy of hitting a desired target.
  • the automatic drilling system is capable of drilling non-stop from "spud” to "TD" along the stored well plan profile and through the target with high accuracy and without assistance, instruction, or interference from the surface in any manner. Oil or gas wells are not normally drilled without pulling the drilling system for various reasons such as setting casing, changing drill bits, or making needed repairs.
  • the quality of hole drilled by this automatic rotary system is much higher than that drilled state-of-the-a ⁇ directional drilling systems.
  • the reasons for this include the following: (1.) In conventional systems, the large deviations of the drilled well from the well plan during periods of no directional control which are subsequently corrected by installation of directional drilling systems cause large amounts of curvature or dog leg in the drilled hole. These macro dog leg effects which cause unwanted torque and drag in the drilling system are eliminated by the subject invention. (2.) The rotating stabilizers and longer open hole times of the conventional systems cause more wear and erosion of the borehole which contributes seriously to trouble and loss of the hole.
  • the speed of drilling is increased or the time to complete the well is decreased by the new system in the following ways: (1.) The. new system uses rotary drilling which is much faster than downhole motor drilling (2.) The new system saves many trips normally required by conventional systems to change designs, exchange worn motors, etc., and (3.) the directional system in no way inhibits the full optimization of rotary drilling parameters such as weight-on-bit, torque, rotary speed or mud flow rate.
  • rotary drilling parameters such as weight-on-bit, torque, rotary speed or mud flow rate.
  • Fig. 15 is a flow chart of the automatic adaptive DRD process for drilling a directional well along the planned profile.
  • the process operates at two distinct levels of automatic homing on the plan: adaptive directional control 752 and drilled profile control 750.
  • the well plan is located in step 702, including location, curvature, and tool face orientation is loaded into the system memory at the surface before beginning drilling in step 704.
  • a decision is made of whether the well plan should be updated. If the decision to update the well plan is "yes", a new plan or modification is supplied from the surface; through the downward communication channel in step 708 or by direct wire replacement in step 709 of the well plan memory.
  • Directional survey data are input in step 716, the surface measured depth, MDs, is downloaded via downward communications from the surface in step 718, and incremental depth data are input and accumulated, ID in step 720.
  • the measured depth, MD MDs +ID, is calculated and the directional data are compiled in the depth domain in step 724.
  • this data is used to calculate the drilled well profile including the location, curvature, and tool face orientation.
  • the drilled well profile control program block 750 asks whether the drilled well location is the same as the well plan location in step 728. If the plan is not the same. a connect plan is calculated in step 730 and substituted for the well plan.
  • the connect plan is typically a relatively short, low curvature plan connecting from the end of the drilled well to a point on the well plan downhole. This connect process assures that the drilled well remains near the well plan and homes on it.
  • the automatic adaptive directional control process shown by block 752 consists of calculating adaptive parameters in step 732 using an adaptive control equation and then using the equation to calculate servo control parameters in step 734. These control parameters are then maintained by servo mechanisms to provide automatic servo control drilling as shown in step 736.
  • step 738 a determination is made of whether the target has been reached. If it is determined that the target has not been reached, the system returns to step 704. Otherwise, the automatic DRD process ends in step 740.
  • the exact nature of the servo control depends on the directional drilling method used (steering method, shear force method, or combination), the geometry of the assembly, the type of controlled stabilizer used, and the actuating means used within the controlled stabilizer, etc.
  • Details of the adaptive directional control process 752 The following is a list of adaptive directional formulae used in the implementation of adaptive control equation (15):
  • N number of samples
  • A TFO, deg. clockwise from high
  • Fig. 16 illustrates the adaptive control process and is a plot of the curvature C. the TFO (tool face orientation) direction A. and lithology as a function of measured depth.
  • the planned values of C p and TFO direction A p are shown as solid lines.
  • the measured values of curvature and standard deviation, C m ⁇ ⁇ C, and the measured values of TFO direction and standard deviation, A m ⁇ OA, are shown as a dot representing the measured value and bars representing the ⁇ standard deviation.
  • the average value of C m Q and A m are shown as solid lines over the
  • d c is not shown in the this case.
  • Another set of measured C and A are taken. The statistical tests show no need to update either f or O.
  • the value of d c is shown.
  • the deviation in A remains statistically insignificant.
  • Many more measured data sets are taken with no update in either f of O.
  • the adaptive system is responsive to the anisotropic drilling properties of the formation not included in the control equation except as as adaptive parameter and 2.) the adaptation to the formation drilling anisotropy (or any element that causes the measured values of C and A to depart from their planned values) is swift and accurate. This speed of reaction is due to the manner in which the measured values are averaged over the last n samples.
  • Fig. 17 illustrates a planned well profile 630 with a solid line, a drilled well profile 632 with a dashed line, and a connect plan profile 634.
  • the connect plan 634' begins at 640 where the drilled well profile 632' ends.
  • the connect plan 634' ends at 642 where it becomes coincident with and in the same direction as the original planned well profile 630'.
  • the connect plan is automatically computed in the downhole system using an algorithm selected to minimize the dogleg.
  • the connect plan method causes the drilled well to continually home on the planned well profile in an optimum manner thus insuring that the drilled well profile always remains very near the plan.

Abstract

Procédé et appareil améliorés servant à contrôler automatiquement la direction de la progression d'une foreuse rotative (30) pour produire un profil de trou de forage pratiquement identique au profil programmé, présentant une courbure minimale, tout en conservant des performances de forage optimales. Le mode d'exécution préféré du système comprend une rame de forage; une tête de forage (30); un système (21) assurant la rotation de ladite tête de forage; un système (24) de mémorisation du trajet de forage prévu; un système (26) recevant des informations utiles pour établir un profil du trajet de forage du trou de forage; un système (10) de comparateur qui compare le trajet foré au trajet prévu et qui génère un signal de correction représentant la différence entre le trajet foré et le trajet prévu; et un système (10) qui réagit au signal de correction en commandant au système de forage de calculer un trajet corrigé afin que le trou de forage percé coïncide avec le trajet prévu.
PCT/US1991/009207 1991-12-09 1991-12-09 Systeme permettant de percer des trous de forage de maniere controlee selon un profil programme WO1993012319A1 (fr)

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PCT/US1991/009207 WO1993012319A1 (fr) 1991-12-09 1991-12-09 Systeme permettant de percer des trous de forage de maniere controlee selon un profil programme
AU13466/92A AU1346692A (en) 1991-12-09 1991-12-09 System for controlled drilling of boreholes along planned profile

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US5931239A (en) * 1995-05-19 1999-08-03 Telejet Technologies, Inc. Adjustable stabilizer for directional drilling
WO2001069035A1 (fr) * 2000-03-15 2001-09-20 Vermeer Manufacturing Company Foreuse directionnelle et procede de forage directionnel
US6467557B1 (en) 1998-12-18 2002-10-22 Western Well Tool, Inc. Long reach rotary drilling assembly
US6470974B1 (en) 1999-04-14 2002-10-29 Western Well Tool, Inc. Three-dimensional steering tool for controlled downhole extended-reach directional drilling
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US6523623B1 (en) 2001-05-30 2003-02-25 Validus International Company, Llc Method and apparatus for determining drilling paths to directional targets
EP2932033A4 (fr) * 2012-12-13 2016-09-28 Schlumberger Technology Bv Commande de trajectoire optimale pour forage directionnel

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US6491115B2 (en) 2000-03-15 2002-12-10 Vermeer Manufacturing Company Directional drilling machine and method of directional drilling
US6523623B1 (en) 2001-05-30 2003-02-25 Validus International Company, Llc Method and apparatus for determining drilling paths to directional targets
EP2932033A4 (fr) * 2012-12-13 2016-09-28 Schlumberger Technology Bv Commande de trajectoire optimale pour forage directionnel

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