BACKGROUND Field of the invention

[0001] This invention relates to an apparatus, a system and a method for autonomous drilling in a geological structure. Applications in the energy and mining industries are anticipated. Prior and related art

[0002] Oil and gas may be produced from a subterranean reservoir onshore or offshore. Such a reservoir comprises a layer of relatively soft rock, e.g. shale or sandstone comprising hydro carbons, and an impermeable layer of harder rock above it. Similarly, valuable minerals, gems and primary metals are mined from geological layers or veins with specific names in their particular branch of mining. For example, diamonds may be mined from a vein termed a Kimberley pipe and primary gold may be extracted from a structure known as a quartz reef. In this disclosure, the specific names of layers or veins used in the mining and/or oil industry are of little or no concern. In the following, the term 'layer' should be construed as any layer or vein of rock, regardless of whether it contains a valuable materia! or not.

[0003] During exploration, drilling and retrieving core samples can determine the presence and extension of a layer containing hydrocarbons, metal ore, gems etc, as well as the concentration of the valuable material within such a layer. During a production phase, drilling is used to create a well extending into a reservoir or to create a borehole for explosives in a mine. In some cases, supporting wells may be drilled, e.g. in order to inject water or gas to stimulate production in an oil field or to maintain ground water pressure around a dam.

[0004] The method of drilling of concern in the present disclosure is generally performed by breaking and/or grinding the rock by a rotary drill bit attached at the end of a drill string. The drill bit has a larger diameter than the drill string in order to create an annular space between the drill string and the surrounding rock. A drilling fluid is supplied through a central bore in the drill string in order to cool the drill bit and convey the cuttings to the surface through the annular space.

[0005] For conveni ence, the invention will be explained by means of drilling as used in the oil and gas industry. However, the invention applies to drilling through rock in general. [0006] In the oil and gas industry, traditional, vertical drilling operations are carried out by a rotary drill string with a drill bit attached to its end. As the drill bit advances, new joints, each a steel pipe about 9 m (30 ft) long, are threaded to the top of the drill string. A typical rig is configured to make up a string in increments of three joints, known as a 'stand' . When the string i s pulled out, the reverse process is called 'break up' and is usually also performed in increments of one stand. The rate of progress during drilling is determined by the weight on the bit, controlled by a hoist carrying most of the weight of the drill string, and the rotational speed controlled by e.g. a rotary table or a keily.

[0007] In addition to its cooling and lubricating functions mentioned above, the drilling fluid, called mud in the oil and gas industry, is used to control the bottom hole pressure by adjusting the density of the mud, e.g. by controlling the amount of clay in the mud. The mud may be based on water or oil.

[0008] The above method provides relatively large rates of progress, i .e. relatively fast drilling of a borehole. This is advantageous due to high rig rates, especially offshore. Further developments forming the background of the present invention include directional drilling, mud motors, steering systems and coi led tubing. These are discussed briefly below. Other topside supportive systems, i.e. on the surface or a rig, e.g. for compensating wave motion on an offshore rig, mud circulation systems etc. known in the art may also be used with the present invention.

[0009] Directional drilling means intentionally drilling a borehole that deviates from the vertical. For example, 40 or more wells may extend, for example, several km in different directions from one offshore rig into various parts of a reservoir. This is profitable due to the cost of building and operating an offshore rig. Several wells per rig is also used in onshore fields, e.g. to reduce environmental impact,

[0010] An important step in the development of directional driving was the mud motor. This device rotates when mud, i.e. drilling fluid, is forced through tangentiaily directed openings and rotates the drill bit about a directional axis. A mud motor allows drilling in places where a rotating drill string would be impossible. However, the power exerted by a mud motor is typically in the order of a few hundred kW, which is far less than the power supplied through a rotating string. Thus, drilling with a mud motor is significantly slower than drilling with a conventional string, and directional drilling often combines the use of a conventional rotating string whenever possible and a mud motor when a rotating string will not work. [0011 ] In order to force a drill string in a desired direction, elements known as whipsticks may be inserted in the borehole on one side of the string. Alternatively or additionally, a bottom hole assembly (BHA) can be configured to alter the direction of drilling. As used in the art, a BHA. essentially is a device compri sing a rotatabie drill bit mounted in a rigid collar and usually other components such as various sensors and a transmitter/receiver for conveying parameters to the surface and receiving control signals from the surface. There are many different types of BHAs. For convenience, the term 'drilling module' is used in the following to denote a steerabie BHA comprising a mud motor. Such a drilling module has a central axis longitudinally through the centre of the collar and a directional axis that is the primary axis of rotation for the drill bit. When rotating downhoie, the drill bit attacks the rock face in the direction of the directional axis. Accordingly, the direction of the borehole can be controlled by adjusting the angle between the central axis and the directional axis. Such drilling modules also have means to compensate for their weight so that they do not unintentionally deviate downwards during directional drilling.

[0012] In some applications, the drill string made up of threaded joints is replaced with a long continuous steel tubing known as coiled tubing. The coiled tubing is delivered on large diameter drums, and allows elastic deformation to a radius of curvature in the order of 10 m. A drilling module as defined above can be attached to coiled tubing in a known manner.

[0013] Drilling is controlled from the surface according to a well plan, i.e. a map of the reservoir and surrounding formation in horizontal and vertical projection obtained by techniques known in the art, e.g. seismic surveying and logging. The plan or map can be updated by data obtained during drilling using techniques known as logging-while-driliing (LWD) and measurement-when-drilling (MWD). Typically, LWD/MWD-parameters are measured at predetermined intervals, for example every 30 m. The data includes information on the direction of the borehole and other parameters. For example, a survey at each point may include the inclination, i.e. the deviation from a vertical line, the azimuth, i.e. the direction with respect to a surface grid of coordinates or an angle from true north, and the measured length of drill string that has passed an odometer on the rig. In directional drilling, the measured length generally does not correspond to the actual depth. Thus, additional data, for example pressure and/or inputs from one or more other sensors to indicate true depth, may form part of such a survey taken up at predetermined intervals. Due to improvements in electronics, in particular piezoelectric MEMS-devices and battery technology, many measurements that were previously performed using bulky equipment, now are performed using small MEMS-accelerometers. For example, a pendulum used to measure inclination can be replaced by a small MEMS-device, and a mechanical gyro compass to determine azimuth is typical! replaced with a MEMS-equivalent. As the sensors are small and cheap, a greater amount of data with better quality is available for the LWD/MWD-applications.

[0014] The LWD/MWD data are transmitted in real time to the surface, e.g. using mud pulses or wired string. Similarly, control signals from an operator on the surface to the drilling module to control the inclination and azimuth of the borehole are sent through the same communication channels.

[0015] Mud pulsing, i.e. pulse modulated signals transmitted through the drilling fluid in the central bore of the drill string, are probably the most commonly used techniques for this two way communication between the surface and the drilling module. Modern mud pul sing may achieve data rates in the order of several tens of bits per second (bps) under favourable conditions. However, the signal quality deteriorates with measured length and depends on the mud. For example, the signal may deteriorate due to reflections caused by diameter variations in the string, and an oil based mud attenuates the signal faster because oil is more compressible than water. Thus, the obtainable data rate may fall from, e.g., about 30 bps at 1 km measured length to 3 bps or less at 10 km measured length in the same borehole.

[0016] The decreasing data rates and the desire for reliable and accurate LWD/MWD-data may decrease the rate of progression, which is expensive as noted initially. Alternatively, a rate of progression may be maintained at the cost, of 'running blind' by increasing the distance between survey points and/or reducing the number of parameters measured at each survey point.

[0017] 'Wired string' is a class of methods in which the communication channel between bottom hole sensors and a topside control centre comprises an electrically conductive wire or optical fibre built into the dril l string. The wire must be properly protected, for example against abrasion when the drill string rotates against the borecole wail in a bend. For this, the wire may be built into the wall of the string, in which case a string made up of stands requires a connection at least one contact et each end of a stand, or more likely one contact at each threaded connection between joints. Alternatively, the wire may be disposed on an external face of the drill sting, which limits its application especially in directional drilling.

[0018] WO20101.15492 represents the state of the art regarding wired strings.

[0019] One problem with the present methods is that the aim and curvature from the surface to the aim are defined a priori, i.e. that the drilling module is steered along a predetermined path towards a predefined target for example to determine the limits of a field on a budget. This may have unintended effects. One example is that Elf stopped drilling at a predetermined target in 1971, and thus missed the North Sea Johan Sverdrup reservoir structure by 3 meters. Johan Sverdrup, formerly known as Avaldsnes and Aldous, may be the second biggest field on the Norwegian shelf after Ekofisk, with an estimated content of 3.3 billion barrels as of November 2011.

[0020] Another problem is caused by the low data rates associated with long measured lengths, especially with oil based mud. Even if a lower rate of progress is selected, the low data rates and distance between the drilling module and a controller, e.g. a central computer or CPU on the surface cause long response times: It simply takes time to send LWD/MWD data several kilometres at low rates, e.g. below 10 bps, and return steering commands over the same distance at the same rate. In addition, the data may require analysis and interpretation by an expert, e.g. a geologist or geophysics st, before a steering command can be issued to the drilling module. This adds to the response time, and hence decreases the rate of progress.

[0021] While a wired string may be used in some applications, there are limitations especially in directional drilling as explained above. Further, the attenuation increases with distance, and repeaters might be needed in an electrical or optical communications cable to maintain significantly higher data rates than those that can be achieved by mud pulsing. Any component added to a communication line within a borehole or weilbore, e.g. a connection between joints or a repeater, adds cost and complexity, and thus increases the risk of failure. Incidentally, these are the main reasons why mud pulsing methods are predominant in the field of borehole telemetry.

[0022 j Thus, the objective of the present invention is to provide a control system to solve at least one of the above problems. The solution should also preferably retain the benefits of prior art.

SUMMARY OF THE INVENTION

[0023] These objectives are met by a control system according to claim 1.

[0024] In particular, the invention concerns a control system for autonomous drilling, comprising an acoustic sensor configured to provide acoustic data in near real time, a CPU and a drilling module with a steerable drilling device and a drilling motor. The CPU is configured to detect a different material based on the acoustic data, and for providing the drilling module with a directional vector independent of a priori or predefined curvature. [0025] The steerable drilling device comprises the drill bit and means for tilting the directional axis, i.e. for directing the directional vector in a desired direction based on input from the acoustic sensor. In embodiments where communication to the surface through an electrical or optical cable is impractical, the CPU would be placed locally in the drilling module, thereby avoiding the response times. It is understood that the autonomous dri lling would continue along one material, i.e. a layer or vein containing a certain type of rock and automatically veer away from boundaries to layers with different acoustic properties regardless of predefined targets or paths, as the predefined well plans may be incomplete or inaccurate. Further, as the requirements for accurate plans or maps are reduced, the control system for autonomous drilling shortens the period of exploration in that less time consuming seismic surveys, core samples and/or logging needs to be performed before drilling to evaluate the extent of a reservoir , a lode or the like.

[0026] In a preferred embodiment, the acoustic data regards a direction of motion for the drilling device and up to 90° from the direction of motion. The direction of motion equals the direction of the directional vector, but their norms and units are different. The hemisphere defined by the 90° limit is sufficient to evaluate all possible changes of direction, as the drilling module will not drill backwards through the existing borehole. Illuminating only the relevant hemisphere saves 50% of the acoustic power compared to illuminating a complete sphere.

[0027] The CPU preferably executes an algorithm for analysing pressure and material in all planes and directions relative to the drilling device. Thus, the algorithm takes account of directions behind the drilling device, i.e. at lest part of the history. This alleviates following a vein or layer.

[0028] Advantageously, the CPU comprises an algorithm that can interpret and analyze acoustic data from the acoustic sensor and that can provide future pressure data in and around the drilling module, whereby the system represents a dynamic BOP. Thus, if the drilling module detects pressure gradients or other indications that could cause a kick, i.e. a sudden increase in pressure, it may be configured to stop immediately, and possibly raise an alarm in the control room, which in turn may decide to activate the main blow out preventer (BOP) of the well.

[0029] Some embodiments comprise a local power source selected from the group consisting of: a replaceable battery package, a piezoelectric generator, a dynamo driven by a drilling fluid and a combination thereof. These embodiments do not depend on electrical power supplied from the surface, and are thus suitable for autonomous drilling modules with a local CPU, i.e. applications where a cabled connection to the surface is deemed impractical or too expensive.

[0030] In the above embodiments, the local power source preferably powers the acoustic sensor, the CPU and a steering mechanism for the drilling device. As saving power may be an issue, e.g. to avoid depleting a battery too quickly, the CPU may be implemented as an embedded low-power device such as an FPGA or ASIC, and the steering device may be controlled by an electrically driven pilot valve whereas the torque required to tilt the drilling device or drill bit is provided hydraulically by the drilling fluid.

[0031] Some embodiments may comprise a cable between the drilling module and the surface for transmitting electric power and/or signals. With a cabled communication line, acoustic data can be conveyed to the surface and control signals responding to the data can be transmitted to the drilling nodule with little or no regard to low data rates in the communication channel. Thus, the controlling CPU might be at the surface in embodiments with an optical or electrical cable. Regardless of whether the controlling CPU is embedded in the drilling module or is situated in or near a control room on the surface, the control system according to the invention would act independently of a human operator, i.e. autonomously, and might be a mode of operation added to a conventional geo-steering system.

[0032] In some embodiments, the cable may supply power to an electric motor driving the drill bit and/or the actuator required to alter the direction of drilling.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention is described in greater detail by means of exemplary embodiments and with reference to the accompanying drawings, in which:

Fig. 1 illustrates a drilling module according to a first embodiment of the invention;

Fig. 2 illustrates a second embodiment of the invention; and

Fig. 3 is a schematic diagram of an acoustic detection and guidance system DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

[0033] The drawings are schematic and not necessarily to scale. Numerous detail s known to those skilled in the art are omitted for the sake of clarity. According to common practice, a distinction is made between 'a/an', meaning 'at least one' and 'one' meaning 'exactly one' . Thus, ' a claw 4' . 'a CPU 12, 'an acoustic sensor 13' should be construed as 'at least one claw 4' etc. Similarly 'the CPU" should be construed as 'the at ieast one CPU' etc. in the present description and accompanying claims.

[0034] Figure I illustrates a drilling module 3 according to a first embodiment of the invention. More particularly, figure 1 i s schematic depiction of a typical steerable BHA with its drill collar 30 sectioned to illustrate components within.

[0035] The dril ling module 3 i s drilling through a layer of rock 200 above a layer 210 of another material by means of an electric or mud powered drilling motor 1 1.

[0036] Drilling fluid or mud is pumped downhole, i.e. toward the right hand side of figure 1 , through the central bore 21 of a drill string 2. In the embodiment on figure 1, the drilling motor 1 1 is a mud motor. Thus, the mud exits through tangential openings 1 10 through the walls of drilling motor 11 into the borehole 201, thereby forcing the motor 11 to rotate about a rotational axis 91.

[0037] The electric or mud powered drilling motor 11 is rotation locked to a drill bit through a shaft 92, such that rotation of the motor 1 1 causes rotation of the drilling device 9, including the drill bit, about, the rotational axis 91. Thus, the direction of drilling i s along the rotational axis 91 of the drilling device 9, as indicated by directional vector 14b. Cuttings from the drilling are conveyed to the surface by the drilling fluid (mud) through the annular space 202 formed between the drill string 2 and the surrounding formation 200.

[0038] it is understood that the power required for drilling, e.g. at least 1 OOkW, in practice requires power supply through an electrically conductive cable from the surface if the drilling motor is electric.

[0039] A dynamic claw 4, i.e. at least one such claw, prevents the drilling module 3 from deflecting downwards during drilling, e.g. at inclinations around 90° as in figure 1. The dynamic claw 4 may be a radially retractable pad, and provide support in the radial direction. The claw 4 may also provide thrust in the direction of direction vector 14b, and thus provide a pull on the drill string 2. It is understood that a velocity vector and a force vector have the same direction as the direction vector 14b, but different norms, i.e. one value measured in m/s and one value measured in N. The claw(s) 4 fold/s), or detracts radially, into the drilling module 3 after the drill string 2 is released, e.g. during retrieval to the surface of drill string 2 and drilling module 3.

[0040] A steerable axle 10 provides local torque and direction control to the drilling device 9. In figure 1, this is illustrated by an actuator 120 that has di splaced the rotational axis 91 through the centre of the steering device 9, i.e. the steerable axle 10, drilling motor 1 1, shaft 92 and the drill bit, an angle φ from a central axis 31 through the collar 30. As the claws 4 retains the collar 30 in the borehole 201, a force applied downward on the end of steering axle 1.0 would cause the drill bit to attack at a new angle, specifically tilting the directional vector 1.4b an angle φ from the previous direction indicated by axis 31. Thus, moving the end of the steering axle 10 up or down changes the direction of drilling, and thereby the inclination of the borehole 201.

[0041] Similarly, moving the end of the steering axle 10 sideways, i.e. into or out of the paper plane in Fig. 1 , would alter the azimuth of the borehole. This can be achieved by a second actuator (not shown) similar to the actuator 120, but acting transversely to the paper plane in figure 1, rather than up and down in the paper plane as the actuator 120. Such a change in azimuth is illustrated by the angle 14 a in figure 3.

[0042] The actuator(s) 120 may be powered with electric power from the topside and associated electronic data communication via at least one power cable, as illustrated by reference numeral 5 in figure 2. However, in a preferred embodiment, control signals from the CPU 12 to e.g. an electromechanical and/or electro-hydraulic (not. shown) valve arrangement, or pilot valve, opens for the drilling fluid, which has sufficient power to provide the force or torque required to move the end of steering axle 10 through the actuator 120.

[0043] An acoustic sensor 13 is provided in the drilling module 3 to provide acoustic data in near real time. In particular, the acoustic sensor 13 emits, e.g. ultrasonic, acoustic pulses and receives echoes. This is discussed in greater detail below. The resulting acoustic data comprises information about different materials in its surroundings, e.g. the different rock types 200 and 210 shown in figure 1.

[0044] As illustrated in figure 1, a different material 210 is detected by the acoustic transducer 13. The acoustic data from the transducer 13, i .e, the acoustic sensor data, are transmitted to a CPU (central processing unit) 12 for analysis. The CPU 12 is adapted, i.e. programmed, to detect changes in the surroundings such as the change in inclination of the different materials 200 and 210 illustrated in figure 1. As a response to the change in inclination, CPU 12 issues a control command to actuator 120, causing the direction vector 14b to tilt vertically by the angle φ. Thus, drilling continues in layer 200, and does not enter layer 210. It is noted that this mode of operation is autonomous in the sense independent of human interpretation of data and of a human operator issuing a steering command. [0045] Figure 2 illustrates an alternative embodiment, wherein the controlling CPU 12 is topside, i .e. at the surface 20. It is understood that the surface 20 may represent a sea surface in an offshore application or solid ground in an onshore application.

[0046] The embodiment in figure 2 illustrates a continuous drill string element I comprising at least one cable 5 for the transmission of electric power and electrical communications/data signals of both analog and digital nature. The string 1 is thus a wired version of the drill string 2 in figure 1. The cable 5 can also include a service channel (not shown ) for the transfer of fluid. However, the drilling fluid pumped down through the central bore (21, Fig. 1) may provide the hydraulic power required to operate devices downhole. Thus, an extra fluid channel is usually not required.

[0047] The drilling module 3 with its steerable drilling device 9 and collar 30 are described in connection with figure 1. A control and communication device 32 is partly shown in fig. 1, and is usually disposed behind the collar 30 as shown in fig. 2.

[0048] The control and communication device 32 is similar to known devices from

LWD/MWD applications in that it contains circuits and logic to convert acoustic sensor signals from the acoustic sensors ( 13, fig. 1 ) into signals fit. for a communication channel to the surface 20. Known communication channels include electrical signals through conductive wires, light pulses through optical fibres and pulses through the mud in the central bore of the drilling string. In the present invention, the control and communication device 32 may contain the CPU 12 depicted in figure 1 and means for communication as in prior art. However, the device 32 in figure 2 would not convey acoustic data through mud pulsing, but might use mud pulsing to raise an alarm . In the context of the present invention, mud pulsing is too slow for providing the response times required for following a layer profile accurately with a desired or reasonable drilling velocity or rate of progression.

[0049] Fig. 3 i s a schematic diagram of an acoustic detection and guidance system. The drilling device 9 can be of a robust design for percussion applications (impact drill) or a drill bit with fixed or variable ("dual") diameter. The end of dril l string 1 further comprises a steering axle 10, a drilling motor 11, a CPU 12 and an acoustic transducer or sensor 13. These components are described above with reference to fig. 1. The directional vector 14b also appears in fig. 1. As indicated in fig. 3, the drilling device 9 can be controlled by an angle 14a with respect to azimuth, and also in an angle 15 around the axis 14b. The third angle 15 must be known to distinguish between inclination and azimuth. For example, the actuator 120 in fig. 1 is not vertical at all times, so an activation of this one cannot be assumed to influence the inclination only. In the example in figure 1, a combination of two actuators 120 perpendicular to each other would be required to alter the inclination ,, and similar for the azimuth. The exact combination depends on the roll angle 15.

[0050] Three spatial dimensions can be represented by three rotational dimensions, e.g. the angles 14a, 15 and φ in figs 1 and 3, or alternatively three translational dimensions, e.g. axes x, y and z in Cartesian coordinates. The directional vector 14b can be oriented according to either set of coordinates. Devices and systems for measuring accelerations, and integrating over time to obtain velocity and position, are generally known. For example, MEMS- acceleroraeters may be used in a known manner to determine position and velocity vectors. However, spatial navigation as such is outside the scope of the present invention, and is not discussed in greater detail herein ,

[0051] Returning to fig. 1 , the CPU 12 changes the direction vector 14b due to a change of inclination in the interface between the materials 200 and 21.0. More particularly, the set of acoustic transducers 13 detects the interface or other material 210, and provides the information to CPU 12. The CPU 12 calculates the proper displacement of the two actuators 120, taking the known position and orientation of the drilling module 3 into account.

[0052] Acoustic detection of matter in all planes and directions relative to the drill unit 9 can be performed by one or more single-element probes or transducers (sensors) 13. The preferred solution however, is the use of one or more "Phased Array" (PA) transducers which electronically can scan volumes of matter. The signal processing is performed using known methods, and is not described in greater detail here.

[0053] However, the invention depends on the fact that acoustic waves propagate differently in different materials. Table 1 below is fetched from Bourbie, T. et. al, "Acoustics of Porous Media", Gulf Publishing Company, Book Division, 1987, and provides an example. Empirical data for relevant materials on the drilling site can be entered in a similar table.

Table 1 : Some acoustic speed - parameters of porous materials

Material P Wave (m/s) S wave (m/s) Density (g/cm2)

Vegetabilst ground

("scree") 300-700 100-300 1.7 - 2.4

Dry sand 400-1200 100-500 1.5 - 1.7

Wet sand 1500-2000 400-600 1.9 - 2.1

Saturated shale/clay 1100-2500 200-800 2.0 - 2.4

[0054] With respect to the acoustic scanning, angle 14a indicates a scan sector in the x - y plane of the velocity vector for the drilling device 9, and 15 indicates scan sector in the x - z plane, variable up to 90 degrees to the x - y plane. That, is, scanning is meaningful in a hemisphere that is symmetric about the directional vector 14b .However, there are no limits to the number of scan - profiles, levels and angles between them, which the at least one acoustic sensor 13 can provide.

[0055] Table 1 indicates the vel ocities of P and S wa ves, and the density of types of matter and combinations of matter. P waves are pressure waves propagating in the longitudinal direction of the matter. S waves are shear waves that are transverse in nature. As fluids cannot convey shear waves, there are no entries for S-waves in oil and water.

[0056] On the basis of, but not limited to, the above theoretical and empirical references, providing at least one CPU 12, based on at least one algorithm and acoustic data from at least one acoustic sensor 13, wherein the at least one sensor 13 provides acoustic data from at least one drilling device 9 at any time the velocity vector in near real time, and varying, but not limited to, up to 90 degrees to the velocity vector at least one drilling element and transmit acoustic data to at least one (preferably locally or downhole located) data processing unit (CPU) 12 having one or more algorithms, for pressure data and matter analysis in all planes and directions in relation to the drilling apparatus. Based on the at least one algorithm, the at least one CPU 12 can provide variable and optimum torque from at least one drilling motor 11, in relation to the surrounding matter (density), to the steerable drilling device 9 in near real time through the steerable axle 10. The at least one CPU 12 can on the basis of the at least one algorithm and recorded acoustic data, make the drilling process autonomous in that it can provide the at least one drilling device 9, 10, a direction vector 14b independently of a priori or predefined curvature (coordinates) to at least one drilling device 9.

[0057] Algorithm(s) controlling autonomy, which overrides the predefined drilling profile (predefined coordinates), will normally be activated when at least one sensor 13 provides acoustic data to be interpreted by at least one CPU 12 to indicate a kind of matter in planes other than occurring to the drilling apparatus at any time pre - programmed direction of movement. This may be, but are not limited to, include hydrocarbons (oil and/or gas), follow mineral ores (precious metals) or volcanic rocks (Kimberley Pipes) for diamond production.

[0058] The system will be able to detect pressure increases ahead in time ("forward looking") through 14a, 14b and /or 15 i.e in the sectors above, below, to the side and in the extension of the velocity vector of the drilling device 9 and can supply drilling fluid components via the service channel 6 of the drill string, and thus represent a dynamic BOP ("Blow Out Preventer").

[0059] If using a mud motor 1 1, this can be controlled via 12 provides which control signals to e. g. electromechanical and or electro-hydraulic (not shown) valve arrangement. If no direct power source 5 is available, a local power supply in example (3), but not limited to, can be incorporated in the form of combinations of interchangeable battery packs, pressure (piezo) electric generators, alternators, or the like, driven by the kinetic energy of the drilling fluid, and thereby providing electricity to power the detection, control and guidance systems defined by reference numerals 10 - 15 as discussed above.

[0060] The target geological features represented by offshore hydrocarbon reservoirs, are located from several hundred meters to several kilometers below the seabed. To minimize the attenuation, the typical frequency range for surface based offshore hydrocarbon seismic search is between 10 - 80 Hz, but frequencies below this level, e.g. 1 - 10 Hz, and above this level, e.g. up to 200Hz, have been reported.

[0061 ] It is noted that the acoustic signals from the transducer 13 need not travel such distances. Hence, much higher frequencies, e.g. ultrasound, can be used in the present invention. The higher frequencies provides for a better resolution than those available from seismic explorations.

[0062] While the invention has been described with reference to specific examples, the scope of the invention is determined by the following claims.