NO345367B1 - Foresighted logging system - Google Patents

Description

BACKGROUND

[0001] In various well-related operations, logging is performed to produce information regarding the underground environment where a well bore is formed. A logging tool is deployed downhole inside the wellbore with a number of different sensors to produce data that is useful for understanding and making use of the well. In some applications, logging-while-drilling methods are used to generate data while a wellbore is being drilled. However, existing logging systems may have limited ability to produce information from certain areas in the underground environment, for example areas in front of or ahead of the logging system. US 2003/0184302 A1 describes an electromagnetic well logging instrument comprising at least one transmitting antenna and two receiving antennas, which are axially separated from the transmitting antenna.

US 2006/0011385 A1 describes a resistivity device with a modular design comprising a transmitter module which is placed at an axial distance from a receiver module on the drill string.

SUMMARY

[0002] The present invention provides a logging-under-drilling system according to claim 1, a method for detecting and measuring one or more underground features according to claim 9 and a method for detecting and measuring one or more underground features according to claim 29. The procedure is suitable for generating data from desired underground areas using a logging system. The logging system is designed for use in a well drilling, and uses a transmitter module with a transmitter antenna. Furthermore, the logging system comprises a receiver module with a receiver antenna, and the receiver module is placed at a distance from the transmitter module. The transmitter antenna and the receiver antenna are oriented to enable sensitivity in desired directions, such as in front of the logging system.

BRIEF DESCRIPTION OF THE DRAWINGS

[0003] Selected embodiments of the invention will be described in the following with reference to the attached drawings, where like reference numbers indicate like elements and where:

[0004] Figure 1 shows a resistivity group according to an embodiment of the present invention;

[0005] Figure 2 shows a resistivity group according to another embodiment of the present invention;

[0006] Figure 3 shows examples of survey depth for an amplitude measurement at 10 kHz made with different distances between transmitter and receiver according to an embodiment of the present invention;

[0007] Figure 4 shows a resistivity group according to an embodiment of the present invention;

[0008] Figure 5 shows a resistivity group according to an embodiment of the present invention;

[0009] Figures 6A and 6B show amplitude responses for traditional prior art resistivity arrays;

[0010] Figures 6C and 6D show amplitude responses for resistivity groups according to an embodiment of the present invention;

[0011] Figure 7 shows a sequencing method according to an embodiment of the present invention;

[0012] Figure 8 shows a resistivity group according to an embodiment of the present invention;

[0013] Figure 9 shows an antenna module according to an embodiment of the present invention;

[0014] Figures 10A - 10F show different measurements for a planar interface with resistivity contrast according to an embodiment of the present invention;

[0015] Figure 11 is a schematic illustration of a logging system for generating data relating to an underground environment, according to an embodiment of the present invention;

[0016] Figure 12 is a schematic illustration corresponding to that in Figure 11, but showing another example of the system, according to an alternative embodiment of the present invention;

[0017] Figure 13 is a schematic illustration similar to that in Figure 11, but showing another example of the system, according to an alternative embodiment of the present invention;

[0018] Figure 14 is a schematic illustration corresponding to that in Figure 11, but showing another example of the system, according to an alternative embodiment of the present invention;

[0019] Figure 15 is a schematic illustration corresponding to that in Figure 11, but showing another example of the system, according to an alternative embodiment of the present invention;

[0020] Figure 16 is a representation that defines an electromagnetic coupling tensor and illustrates how it relates to antenna orientations, according to an embodiment of the present invention;

[0021] Figure 17 is a model representation of the logging system used in a mainly vertical well, according to an embodiment of the present invention;

[0022] Figure 18 is a model representation of the logging system used in a mainly horizontal well, according to an embodiment of the present invention;

[0023] Figure 19 is a graphical presentation of results fed out of one example of the logging system in a mainly vertical well, according to an embodiment of the present invention;

[0024] Figure 20 is a graphical representation of results fed out of one example of the logging system in a mainly horizontal well, according to an embodiment of the present invention;

[0025] Figure 21 is a schematic representation of an example of a logging system using a system with three transmitters and one receiver, according to an alternative embodiment of the present invention;

[0026] Figure 22 is a graphical representation illustrating the use of tilted directional transmitter (TX) and receiver (RCV) antennas, according to an embodiment of the present invention;

[0027] Figure 23 is a graphical representation of results output from one example of the logging system illustrating tool sensitivity associated with a down-stepped resistivity profile for a given set of parameters, according to an embodiment of the present invention;

[0028] Figure 24 is another graphical representation of results output from one example of the logging system illustrating tool sensitivity associated with a down-stepped resistivity profile for another set of parameters, according to an embodiment of the present invention;

[0029] Figure 25 is another graphical representation of results output from one example of the logging system illustrating tool sensitivity associated with a down-stepped resistivity profile for another set of parameters, according to an embodiment of the present invention;

[0030] Figure 26 is another graphical representation of results output from one example of the logging system illustrating tool sensitivity associated with a down-stepped resistivity profile for another set of parameters, according to an embodiment of the present invention;

[0031] Figure 27 is another graphical representation of results output from one example of the logging system illustrating tool sensitivity in connection with an upward-stepped resistivity profile for a given set of parameters, according to an embodiment of the present invention;

[0032] Figure 28 is another graphical representation of results output from one example of the logging system illustrating tool sensitivity associated with an upward-stepped resistivity profile for another set of parameters, according to an embodiment of the present invention;

[0033] Figure 29 is another graphical representation of results output from one example of the logging system illustrating tool sensitivity associated with an upward-stepped resistivity profile for another set of parameters, according to an embodiment of the present invention;

[0034] Figure 30 is another graphical representation of results fed out of one example of the logging system illustrating tool sensitivity associated with an upward-stepped resistivity profile for another set of parameters, according to an embodiment of the present invention;

[0035] Figure 31 is a graphical representation of look-ahead range as a function of TX/RCV distance for attenuation and phase shift with respect to both up-stepped and down-stepped resistivity profiles, according to an embodiment of the present invention;

[0036] Figure 32 is a graphical representation regarding an example of the logging system with respect to attenuation range sensitivity with respect to resistivity levels and contrast for a down-stepped formation resistivity profile at two different transmission frequencies, according to an embodiment of the present invention;

[0037] Figure 33 is a graphical representation illustrating detection range and down-stepped resistivity profiles at two resistivity contrasts, according to an embodiment of the present invention;

[0038] Figure 34 is a graphic illustration showing examples of downward-stepped profiles and other information regarding the use of one example of the logging system, according to an embodiment of the present invention;

[0039] Figure 35 is a graphic representation illustrating examples of results that can be obtained using the logging system regarding anisotropy and relative inclination of the formation, according to an embodiment of the present invention;

[0040] Figure 36 is a graphical representation illustrating examples of measurements as a function of four different structural slopes, according to an embodiment of the present invention;

[0041] Figure 37 is a graphical representation illustrating examples of measurements fed out of the logging system that represent determination of underground features, such as the proximity and existence of contaminated sand (dirty sand position), according to an embodiment of the present invention;

[0042] Figure 38 is a graphical representation illustrating examples of measurements fed out by the logging system that represent estimates of layer thickness, according to an embodiment of the present invention;

[0043] Figure 39 is a flowchart representing one example of a method for generating data with the logging system where direct inversion is used, according to an embodiment of the present invention;

[0044] Figure 40 is another flowchart representing an example of a method for generating data with the logging system where direct inversion is used, according to an embodiment of the present invention;

[0045] Figure 41 is a schematic illustration of an example where predictive inversion is used by the logging system to determine information regarding the underground environment, according to an embodiment of the present invention;

[0046] Figure 42 is a schematic illustration of another example where predictive inversion is used by the logging system to determine information regarding the underground environment, according to an alternative embodiment of the present invention; and

[0047] Figure 43 is a schematic illustration of another example where predictive inversion is used by the logging system to determine information regarding the underground environment, according to an alternative embodiment of the present invention.

DETAILED DESCRIPTION

[0048] In the following description, a number of details are indicated to provide an understanding of the present invention. However, it will be understood by those skilled in the art that the present invention can be practiced without these details and that a number of variations or modifications of the described embodiments may be possible, which fall within the scope of protection of the appended claims.

[0049] Embodiments of the invention relate to resistivity groups with improved properties. Some embodiments of the invention relate to methods for using these tools in formation evaluation.

Embodiments of the invention may enable inversion for more complicated formation models (ie formation models with more parameters) and/or may improve the robustness of inversion of resistivity measurements (reduce uncertainty). Some embodiments of the invention may increase flexibility in evaluating a formation's resistivity by providing multiple measurements, each of which may have a different response to different formation models.

[0050] Some embodiments of the invention provide resistivity groups with a modular structure. The modular structure facilitates the setup of different tool designs for different measurement requirements. For example, by expanding the number of transmitter/receiver combinations (for example, an embodiment with four transmitters and one receiver, forming four transmitter/one receiver groups), one can achieve a greater depth of sub-selling.

[0051] Some embodiments not according to the invention can include antennas that can serve as a transceiver (ie as transmitter and receiver). This provides additional flexibility in tool design. In this embodiment, a larger number of transmitter/receiver combinations can be achieved with the same number of modules. Furthermore, symmetrization of direction measurements can be achieved without increasing the length of the tool, in a manner similar to the published US patent application 2003/0085707 A1, by Minerbo et al.

[0052] Some embodiments of the invention relate to tools with a transmitter component located far from the receiver (eg, > 27.40 meters (90 feet)) to enable selective sensitivity to reservoir complexity. Such an embodiment may have an independently powered transmitter component located outside (well away from) a traditional downhole unit.

[0053] Some embodiments of the invention relate to placing a transmitter on or inside the drill bit, or very close to the drill bit, for predictive function. Such an embodiment may have an independently powered system and enable data communication.

[0054] Some embodiments of the invention relate to having at least one module arranged in a separate well or a separate borehole.

[0055] Some embodiments of the invention relate to methods for evaluating formation resistivity that use measurement frequencies specially adapted to the expected formation. The frequency range can be, for example, up to 200 KHz.

[0056] Some embodiments of the invention relate to combining modules according to the invention with existing LWD resistivity groups.

[0057] Some embodiments of the invention relate to coil designs having multiple windings to enable the use of the same antenna for a large range of frequencies. The several windings can be connected in series or in parallel.

[0058] Some embodiments of the invention relate to the extension of the amplitude measurement to phase, relative phase and amplitude as well as phase shift and attenuation (propagation) which requires that a component comprises two receiver antennas with a relatively large mutual distance, in the order of 3.5 meters (10 foot).

[0059] Some embodiments of the invention relate to the realization of directional antennas (arranged in the same place or close to each other) with or without metal shielding.

Tool modularity

[0060] Some embodiments of the invention relate to resistivity groups with a modular structure. By a "resistivity group" here is meant an arrangement comprising at least one receiver module and at least one transmitter module fixed at different places on a drill string. The modular structure means that the transmitter and receiver antennas can be placed at different locations inside a downhole unit (BHA), or at locations in the drill string above the downhole unit. For example, Figure 1 shows a resistivity group comprising four transmitter modules 21, 22, 23, 24 and one receiver module 25 arranged among other LWD or MWD tools 27, 28, 29, 30 in a BHA. By inserting transmitter and/or receiver modules at different locations on a standard BHA, as shown in Figure 2, or a drill string, specific survey depths can be realized to optimize the process of inverting the formation model using these deep resistivity measurements. For example, in one embodiment, the transmitter module 21 may be located approximately 27.4 to 30.5 meters (90 to 100 feet) from the receiver module 25. Additionally, one or more modules may be disposed in a nearby borehole to form an array of large distances.

[0061] The inventors behind the present invention have found that too great an increase in the distance between a transmitter and an associated receiver antenna makes it difficult for a receiver to pick up and connect the signals from a transmitter.

Embodiments of the present invention can use a triaxial antenna in a transmitter or receiver module, where the triaxial antenna module has three antennas with magnetic moments in three different directions. The triaxial antenna module will ensure that at least some of the transverse components of the triaxial antenna can form a significant connection with the transverse component of an associated transmitter or receiver. Using a transceiver (or receiver) with a triaxial antenna is advantageous because when the drill string is assembled, it would be difficult to ensure that a transmitter with a single antenna will be aligned with a receiver with a single antenna, and this problem increases over time as the distance increases. In contrast, the transceiver (or receiver) with a triaxial antenna will always have a component that is approximately aligned with the magnetic moment of an associated receiver (or transceiver) in the resistivity group. In addition, three axes enable determination of formation properties such as inclination angle, anisotropy, side rock effects.

[0062] Figure 3 shows examples of survey depths for a 10 kHz amplitude measurement obtained with transmitter/receiver distances of 3.05, 9.15, 18.30 and 27.4 meters (10, 30, 60 and 90 feet) in presence of an interface with a resistivity contrast of 1 to 10 ohms. The drill string (and thus the resistivity group) is assumed to be parallel to the interface and at different distances away from the interface. As can be seen in Figure 4, the group with a mutual distance of 3.05 meters is not very sensitive to the interface; it shows only small size changes near the interface. The group with a mutual distance of 9.15 meters is more sensitive, and shows a clear transition in the interface. The group with a mutual distance of 18.3 meters is even more sensitive; it shows a very clear transition in resistivity around the interface. At this distance between transmitter and receiver, the magnitude of the signal begins to change at approximately 6.10-12.20 meters (20-40 feet) away from the interface. With the group with a mutual distance of 27.4 metres, the change in the magnitude of the signal is even greater. It is clear that the combination of different survey depths makes it possible to distinguish geological formations with different radial distances. The modular structure makes it easy to adjust the tools for different distances in the group. Furthermore, the use of one or more triaxial antennas as transmitters and/or receivers increases the mutual distance that can be achieved, which gives a corresponding increase in depth of investigation (DOI).

Modular components such as transceivers

[0063] Some embodiments of the invention relate to the design of resistivity groups with transmitter/receiver antennas. In these tools, the antennas are not designed as separate transmitters or receivers. Instead, one and the same antenna can act as either transmitter or receiver. Such an improvement, in addition to being economically beneficial, enables more investigation depth for the same number of components, as illustrated in Figure 2.

[0064] Figure 2 shows a tool unit 40 with three components 41, 42, 43 which form two groups with mutual distances D and Dx2. Since the antennas 41 and 43 can function as transmitter or receiver, a third group with mutual distance Dx3 is also available with this tool design. With the transceiver antennas, further direction measurements can also be carried out without the need for the transmitter and receiver to belong to a common downhole tool. For example, a set of symmetric measurements can be produced first with antenna 41 as transmitter and antenna 43 as receiver, and then with antenna 43 as transmitter and antenna 41 as receiver.

Remove components such as transmitters/transceivers

[0065] Some embodiments of the invention relate to tools with antenna components located far away from other BHA tools (eg the receivers or transmitters). Wells often have turns and bends that limit the practical length of a BHA. Consequently, traditional resistivity tools cannot have transmitters and receivers spaced further apart than the practical downhole unit length limitation (approximately 46 meters (150 ft)). Such tools are not capable of providing the depth of investigation that may be required when locating a well path within a reservoir with a thickness that exceeds the maximum practical length of a standard drilling tool unit.

[0066] Figure 4 shows a resistivity array incorporating a remote component according to one embodiment of the invention. As shown, the resistivity group includes a traditional UDR (Ultra Deep Resistivity) 51 in the BHA. The UDR comprises three antennas (transmitters, receivers or transceivers) 52, 53, 54. Further up the drill string, the resistivity group also comprises a remote module 55, which comprises a transmitter, a receiver or a transceiver. The antenna in the remote module 55 can be used with any of the antennas 52, 53, 54 to form a widely spaced array. By using a remote module 55 with other traditional resistivity tools in the bottom hole assembly, the transmitter/receiver spacing (ie intergroup spacing) can be set to any desired spacing. The remote module 55 may be independently powered. Furthermore, the remote module 55 can for example be activated by means of wireless telemetry. In one embodiment, one or more neck tubes 63 can be arranged between the remote module 55 and one or more of the antennas 52, 53, 54.

[0067] The position of the remote module 55 can be chosen in the same order of magnitude as (or greater than) the thickness of the reservoir. Having a mutual distance within the group in the same order of magnitude as (or greater than) the thickness of the reservoir can provide special advantages that are otherwise unavailable to traditional resistivity tools.

[0068] For example, Figures 6C and 6D show that the amplitude responses of the long group (where the mutual distance is of the same order of magnitude as the layer thickness, 39.6 meters (130 feet)) are much simpler and clearly indicate where the layer boundaries are. The responses of this extra long group (especially at low frequencies) are not sensitive to the internal complexity of the reservoir. In contrast, as can be seen in Figures 6A and 6B, the amplitude response of traditional prior art resistivity arrays (where the mutual distance is less than the layer thickness, 39.6 meters) is more sensitive to resistivity variations within the layer, but less sensitive to layer boundaries. Results from Figures 6A-6D show that sensor distances (distance within the group) and operating frequencies can be advantageously chosen based on the properties of the reservoir being drilled, for example expected layer thickness or the ratio between the lowest reservoir layer resistivity and the resistivity of the roof rocks and the reservoir bottom.

Predictive function with components at the drill bit

[0069] Some embodiments of the invention relate to resistivity tools with the ability to see ahead. According to embodiments of the invention, a component can be placed close to the drill bit in a manner similar to that described in US patent 6,057,784 granted to Schaff et al., and transferred to the same as the present invention. Furthermore, an antenna can also be placed on a rotating controllable tool or directly inside a drill bit. By placing a transceiver at the drill bit, the resistivity measurement point taken in the middle of each transmitter/receiver pair is moved closer to the drill bit, thus enabling a shorter reaction time during drilling. This possibility enables earlier implementation of measures in real time to position the well based on geological events. Furthermore, it is also possible to see in front of the drill bit by using the tool response tail which passes a pair of resistivity sensors.

[0070] Figure 5 shows an example of a resistivity group according to one embodiment of the invention. As shown, the resistivity tool comprises a drill bit 14 at one end of the drill string. An antenna 73 (which can be a transmitter or a receiver antenna) is arranged on the drill string close to the drill bit 14. In addition, the resistivity group comprises a UDR 51 with three transceiver modules 52, 53, 34, which can function as receivers or transmitters. Although three transceiver modules are shown in this example, those skilled in the art will appreciate that such a tool may have more or fewer transceiver modules. Furthermore, receiver or transmitter modules can replace one or more of the transceiver modules. In one embodiment, the antenna 73 may be a component of the drill bit 14.

[0071] According to some embodiments of the invention, the antenna 73 near the drill bit has a non-longitudinal magnetic moment, i.e. that the magnetic moment of the antenna 73 is not in a direction parallel to the drill string axis. The non-longitudinal magnetic moment of the antenna 73 ensures that the antenna 73 has a component of the magnetic moment in the transverse direction (ie the direction perpendicular to the drill string axis). Furthermore, at least one of the transceiver modules (e.g. 52, 53, 54) comprises a triaxial antenna, where three antennas have magnetic moments with three different orientations. In some cases, the triaxial antennas can have magnetic moments in three orthogonal directions. The triaxial antenna module will ensure that at least some of the transverse components of the triaxial antenna can form a significant connection with the transverse component of the antenna 73 closest to the drill bit.

The antenna 73 closest to the drill bit can be a transmitter, a receiver or a transceiver. In general, it is preferred that the antenna 73 closest to the drill bit is a transmitter because a receiving antenna will be able to see stronger electrical noise from increased vibration and shaking or from the possible presence of a high power, rotating steerable tool. As a result, the motor unit 16, which may include motor-driven control components, can interfere with a receiving antenna.

Multi-frequency measurement

[0072] Some embodiments of the invention relate to tools and methods that use several frequencies for resistivity measurement. According to embodiments of the invention, frequencies can be selected so that they more effectively cover the frequency spectrum to improve accuracy and increase flexibility when inverting deep resistivity measurements. For example, according to some embodiments of the invention, measurements may be collected with a distribution of 3 or more frequencies for each decade (interval spanning a factor of 10).

These frequencies can be set or selected automatically, either before drilling or during drilling, to provide optimal formation inversion. The combination of transmitter/receiver distance with frequency is an essential part of determining the outer limits of a reservoir with complex internal layers. The combination of antenna distance and frequency is preferably chosen so that it takes into account the following equation for maximum sensitivity.

[0073] Let us define the frequency coefficient k as: k<2 >= εµω<2 >+ iσµω , where ε is electromagnetic permittivity, µ is electromagnetic permeability, σ is conductivity and ω is angular frequency. If L represents the distance between transmitter and receiver, we want that: |k|.L�[0,1;10]. The frequencies are preferably chosen so that they meet this criterion.

[0074] The multi-frequency measurements can be effectively carried out using any implementation scheme known to the person skilled in the art. For example, Figure 7 shows an example of resistivity measurement sequence for multi-frequency measurement. In the scheme shown in figure 7, all the TX pulses are assumed to have controlled amplitude. Furthermore, the person skilled in the art will know that in the pulse pattern, as shown in Figure 7, a single pulse can be used to carry two or more frequencies. Signal measurements can be performed by measuring the true voltages sensed by the receivers. Alternatively, the signals can be measured as difference signals between a pair of pulses with different frequencies.

Combination of Components with Existing LWD Tools [0075] Some embodiments of the invention relate to resistivity arrays having remote components, as described above, along with other traditional resistivity tools. For example, Figure 8 shows a tool comprising two remote components with transmitters 55A and 55B and a traditional LWD resistivity tool that can act as receivers for the remote transmitter modules to form arrays with spacing much longer than is possible with traditional resistivity arrays . Those skilled in the art will appreciate that any traditional resistivity tool with one or more antennas to receive resistivity signals can be used in conjunction with remote component transmitters as described herein. The ability to run transmitter modules in combination with an existing "shallow" LWD tool (using their resistivity antennas as deep resistivity receivers) enables cost rationalization and integrated measurement capability.

Antenna with multiple windings

[0076] Some embodiments of the invention relate to antennas that can be used effectively over a wide frequency range. When an antenna is used to send out a resistivity signal with a given frequency, the antenna is most efficient when the frequency is lower than the antenna's self-resonance frequency. When a given antenna is used over a wide frequency range, the antenna may therefore be inefficient in certain frequency ranges. For example, to transmit at the highest frequency, the number of turns in the antenna should be small enough that one is lower than the natural frequency of the coil. To be optimal when transmitting at a lower frequency, however, the number of windings must be increased. As a result, traditional antennas often have windings that represent a compromise for the intended range of operating frequencies.

[0077] According to some embodiments of the invention, an antenna can have several layers of windings; each of the layers can be connected either in parallel for high frequency or in series for a lower frequency to effectively balance the impedance load on the antenna when operated with constant voltage. Switching between serial and parallel function can be controlled electronically.

[0078] Figure 9 shows an example of an antenna according to one embodiment of the invention. A coil layer 101A-101C, in this example, is either connected in series to maximize the number of turns when transmitting at a low frequency (for example, in the region of 1kHz), or is connected in parallel for a higher frequency range (for example, 100 kHz). The coil layers 101A-101C are wound around a stem 102. Those skilled in the art will know that several layers of coils can be used in an antenna to enable finer tuning of the antenna's performance.

Extension to other resistivity measurement methods

[0079] Traditional deep resistivity measurements, such as that described in US Patent 6,188,222, are based on an induction mechanism and measure signal amplitude, not phase or phase shift or attenuation. Some embodiments of the invention relate to deep resistivity measurements based on a propagation mechanism and measure phase shift and attenuation (ie, difference measurements) by introducing an additional receiver antenna with a distance between the receiver pair on the order of 1.5 to 3 meters (5 to 10 feet), which is significant longer than the distance between the receiver pair (typically limited to less than 30 cm) in a traditional propagation tool. The greater distance between the receiver pair is desirable because of the lower frequencies used for deep EM measurement (1 to 200kHz). A distance between the receiver pairs of the order of 1.5 to 3 meters will ensure that the smallest phase shift that can be measured is in the range of ~0.1 degrees.

[0080] In addition to using a pair of receivers, difference measurements in phase and amplitude (i.e. phase shift and attenuation) can also be performed with a suitable pulse scheme, as shown in Figure 7. The measurement scheme shown in Figure 7 can use one (or more ) of the emitted pulses at a given frequency as a time reference. Assuming a constant phase reference (or time difference) between pulses in the pulse train (this time difference can also be measured and communicated to the receiver using wireless telemetry), the phase reference (or time difference) of the received pulse trains can be determined with respect to the reference pulse.

[0081] The same method (which uses the amplitude of a reference pulse for comparison) can also be applied to the amplitude ratio between each pulse in the pulse train and the reference pulse. In this case the amplitude ratio at the transmitter can be kept constant or measured. The difference method in pulse arrival time and amplitude ratio reduces the measurement's dependence on accurate air calibration, which is required for the amplitude measurement.

[0082] As an example, Figures 10A - 10F show various measurements for a planar interface with a resistivity contrast of 1 and 100 ohms, using a tool with a transmitter/receiver distance of 21.3 meters (70 feet). This tool has transmitter and receiver antennas with longitudinal magnetic moments (ie magnetic moments in a direction parallel to the longitudinal axis of the tool).

[0083] Figure 10A and Figure 10B show respectively amplitude measurements and relative amplitude measurements, at different frequencies. In Figure 10B, the relative amplitude measurements are in relation to the amplitude measurement at 2 KHz. Figure 10C and Figure 10D show phase measurements and relative phase measurements, respectively, at different frequencies. In figure 10D, the relative phase measurements are in relation to the phase measurement at 2 KHz.

[0084] Figure 10E and Figure 10F show phase shift measurement and attenuation, respectively, at different frequencies, as measured with a pair of receivers spaced 2.44 meters (8 feet) apart. With such a receiver distance, significant variations in phase shift and attenuation can be clearly observed. Both measurements provide a different set of measurements with different sensitivities, making it possible to use more independent measurements during the inversion process.

[0085] Some embodiments of the invention relate to geosteering. A method of geosteering according to embodiments of the invention can use any resistivity group described above and/or use a measurement method described above (e.g. multi-frequency measurements, use of a pulse pattern, etc.).

[0086] All measurements with the above-described embodiments of the invention can be extended to directional measurements. Directional measurements enable increased sensitivity to the interfaces and will improve the inversion process accordingly. In some embodiments, the antenna(s) have a transverse magnetic dipole combined with a normal "axial" antenna to provide both measurements from the same antenna. In a triaxial antenna, as discussed above, one part can be aligned with the axis of the bottom hole unit, while the other two parts are inclined relative to this. Traditional screens can also be used with embodiments of the invention as desired. It will be understood that the antennas (and associated electronics) in the embodiments of the invention can be realized using one of many well-known antenna designs and packaging systems. For example, the logging apparatus described in U.S. patent 6,188,222 can be used to realize the present invention.

[0087] Although the embodiments described here illustrate logging-while-drilling tools as an aid in explaining various embodiments of the invention, a tool according to the invention is not limited to any concrete guiding method. A tool according to the invention can thus be used, for example, during operations such as logging-under-drilling, logging-under-tripping, coiled pipe drilling, logging through the bit, extension pipe drilling, feed pipe drilling.

[0088] According to an alternative embodiment of the invention, another system and another method facilitate the production of data relating to an underground area. For example, a predictive logging-under-drilling system can be used to facilitate the detection and measurement of various features and properties in the subsoil. The logging-while-drilling system can "look ahead" by producing data from areas ahead of the logging-while-drilling system, for example during the drilling of a wellbore.

[0089] Figure 11 illustrates an example of a system 40 which is used to perform logging operations in a wellbore 42 according to one embodiment of the present invention. In the illustrated embodiment, the system 40 comprises a logging sub-drilling system 44 combined with a tool, such as a downhole unit 46. The downhole unit 46 may comprise a drill bit 66 which is used to drill the wellbore 42 simultaneously with logging of an underground area 48 where the wellbore 42 is formed .

[0090] In the illustrated embodiment, the downhole unit 46, comprising the logging-under-drilling system 44, can be guided downhole by means of a guide device 50. The guide device 50 can be in the form of drill pipe, coiled pipe or another suitable type of guide device. Furthermore, the system 40 may include a control system 52 connected to the logging-while-drilling system 44 via a suitable cable-based or wireless communication line 54. As an example, the control system 52 may include a computer-based control system for processing data received from the logging-while-drilling system 44. The data/process results may be displayed for use by an operator on a suitable display device 56, such as a computer screen, disposed on the surface.

[0091] In the example in Figure 11, the logging-while-drilling system 44 comprises a transmitter module 58 with a transmitter antenna 60 and a receiver module 62 with a receiver antenna 64. In the specific example that is illustrated, the logging-while-drilling system 44 comprises several, f .ex. two, receiver modules 62. The transmitter module 58 and the receiver module or modules 62 are arranged at separate locations along the bottom hole assembly 46, and the spacing is chosen to provide a desired survey depth. The transmitter module 58 is located close to a drill bit 66 on the bottom hole unit 46. For example, the transmitter module 58 can be arranged on a component 68 behind a drill bit 66 or otherwise close to the drill bit. With such a system, a measurement point (taken as the midpoint between the transmitter module 58 and the receiver module 62) is pushed towards the drill bit 66 in a way that provides not only radial sensitivity, but also sensitivity in front of the transmitter antenna 60.

[0092] In the embodiment illustrated in Figure 11 and in other embodiments described below, different antenna arrangements can be used. For example, the transmitter module 58 can have an inclined antenna 60. Using an inclined antenna means that the magnetic dipole moment is not aligned with the tool axis, e.g. axis of the downhole assembly, and the magnetic dipole moment is also not perpendicular to the tool axis. The receiver module 62 may also use an inclined antenna 64, or its antenna 64 may comprise an axial antenna where its magnetic dipole moment points along the tool axis or perpendicular to the tool axis. In one useful embodiment, the total number of antennas in the transmitter and receiver modules is four, and many arrangements of these four antennas are possible.

[0093] Although the antennas are described with respect to magnetic dipole antennas, the antennas 60, 64 may also comprise electric dipole antennas. As an example, magnetic dipole antennas, such as coils, can be used in induction and/or propagation measurements. Electric dipole antennas can use electrodes and/or toroids. Depending on the specific application, the role of the transmitter antennas and the receiver antennas can be reversed.

[0094] The embodiment of the system 40 illustrated in Figure 11 places the transmitter module 58 directly behind the drill bit 66. As an example, the transmitter module 58 and the antenna 60 can be placed in a drill bit box 70 on a mud motor 72 that is used to drive the drill bit 66. It should be noted that each transmitter module 58 can also include one or more sensors 74 and associated electronics 76 which are supplied with power through an external or internal line or by an inserted battery. The logging-while-drilling system 44 may additionally incorporate a variety of other modules 78, which may include a variety of different tools or sensors depending on the specific logging operation expected for a given application.

[0095] In Figure 12, a corresponding embodiment is illustrated where the drill bit 66 is driven by a rotating controllable system 80. As an example, the embodiments illustrated in Figures 11 and 12 can place sensors 74, e.g. electromagnetic sensors, directly behind the drill bit 66 or have them integrated with the drill bit 66. In alternative embodiments, the sensor or sensors 74, together with the associated electronics 76, can be arranged directly on the rotating controllable system 80, as illustrated in Figure 13, or on the mud motor 72, as illustrated in figure 14. In the embodiments described above, a number of different antennas can be used. For example, the transmitter antenna 60 may be formed as a triaxial TX antenna and the receiver antennas 64 may be formed as triaxial RCV antennas. The associated sensors can be individual sensors or combinations of induction/propagation sensors and/or laterolog sensors. In another embodiment illustrated in Figure 15, the antennas are toroidal electric dipole antennas which may be particularly useful for wells drilled with oil-based mud. In this embodiment or other embodiments, additional components, such as a centering assembly 82, may be incorporated into the bottom hole assembly 46.

[0096] In general, having transmitter antennas at the drill bit is useful because power is usually more readily available. For example, a rotary steerable system often uses a turbine from which power can be taken. Furthermore, receiver antennas located on or near the drill bit are expected to have higher noise levels than conventional logging-downhole tools because of the more vibrating environment (microphonic noise) on or near the drill bit and because of the significant amount of electrical power typically used by the rotating controllable system.

[0097] A directional antenna is an antenna with a dipole moment that is not aligned with the tool axis. With one or more directional transmitter antennas 60 arranged on or near the drill bit 66, measurements can be made that are sensitive to drafts in front of the transmitter antenna and the drill bit. Often, voltage measurements are made for the amplitude and phase of the voltage induced at the receiver antennas 64 by a signal from one or more transmitter antennas 60. The voltage is proportional to the direction and absolute value of the dipole moments of the transmitters and receivers via an electromagnetic coupling tensor. The coupling tensor depends on the frequency of the emitted signal, the distance between transmitter and receiver and the formation parameters.

[0098] Figure 16 shows an illustration to define an electromagnetic coupling tensor and to show how it relates to the antenna orientations. In the example in Figure 16, the Z axis points along the tool axis, and the X and Y axes are perpendicular to each other and to the Z axis. The first letter of the coupling tensor component corresponds to the direction of the receiver dipole moment, and the second letter corresponds to the direction of the transmitter dipole moment. After voltage measurements are made and the orientation and magnitude of the transmitter and receiver antennas' dipole moments are known, the electromagnetic coupling tensor can be determined. To derive properties of the features in front of the drill bit 66, one can use the electromagnetic coupling tensor, or the electromagnetic coupling tensor can be transformed into its corresponding formation parameter tensor, for example a conductivity tensor, which can then be used to derive desired properties of the subsoil area in front of the drill bit. Individual components of these tensors, or different combinations of the components, can be used to derive formation properties. For example, any of the following combinations may be used:

ZZ/(XX+YY), sometimes referred to as "harmonic resistivity" (HR);

(ZZ-XZ)/(ZZ+XZ)*(ZZ+ZX)/(ZZ-ZX), sometimes termed "symmetrized direction" (SD) or "first harmonic direction";

XX/YY, sometimes designated "second harmonic direction"; and

(ZZ+XZ)/(ZZ-XZ)*(ZZ+ZX)/(ZZ-ZX), sometimes termed "anti-symmetrized direction" (AD).

[0099] Each measurement contains information about the structure of the formation (resistivity, layering, slope and other parameters). In operation, a response is measured which is sensitive to the surrounding formation, including determination of a layer (bed) in front of the drill bit 66 if such is present. A simulated response can also be generated by modeling a wellbore without any interface in front of the bit. The difference between the actual response and the modeled response is calculated, for example, using the control system 52. If the difference is zero, it can be concluded that there is no layer in front of the drill bit, but if the difference is not zero, it can be concluded that the difference can be attributed to the presence of one layer in front of the drill bit.

[0100] Figures 17 and 18 show illustrations of modeling setups used to generate the elementary links. The elemental connections are generated according to the orientation of the downhole unit in relation to the formation. For example, the modeling setup illustrated in Figure 17 represents a predominantly vertical orientation, and the modeling setup illustrated in Figure 18 represents a predominantly horizontal orientation. The illustrated formation may also have a relative slope to the bottomhole unit.

[0101] Referring generally to Figures 19 and 20, graphical examples are illustrated representing results from the logging system 44 when constructed as an induction tool with a predetermined distance between transmitter and receiver (T-R) antennas and a predetermined frequency when crossing a formation with a given thickness. As an example, the T-R distance is 18.3 meters (60 ft) and the frequency is 2 kHz when traversing a 1.5 meter (5 ft) thick formation. As an example, the results can be displayed on a display device 56 in a suitable control system. In Figure 19, an example with a forward-looking function is shown where the well is mainly vertical, and in Figure 20 an example with an all-round function is shown where the well is mainly horizontal. In these examples, the response is the difference between signals generated with and without a layer in front of the bit 66.

The response is expressed both as an amplitude ratio on the left graph in each figure and as a phase difference on the right graph in each figure. In the mainly vertical example in Figure 19, the cross-connections ZX and XZ are zero.

[0102] In the example with a neglecting function illustrated in Figure 19, only the diagonal terms in the coupling tensor (XX, YY and to a lesser extent ZZ) and ZZ/(XX+YY) show a dependence on the formation that can be used. It should be noted that the ratio ZZ/(XX+YY), when used in formations with low inclination and anisotropy, does not change drastically. In this example, at a distance of approximately 15.2 meters (50 feet) above the layer, the amplitude ratio response begins to deviate from zero, indicating the presence of a layer of different resistivity in front of the bit. As the tool/downhole unit approaches the layer, the deviations increase until the first antenna crosses the layer boundary, when the response has its maximum value. Likewise, the phase difference of the responses begins to deviate from zero at approximately 18.3 meters (60 feet) above the layer boundary, as shown in the right graph in Figure 19. In the responses shown, there is a crossover point at approximately 6.1 meters (20 feet) above the layer which, in addition to the above-mentioned deviations, indicates that there is a layer in front of the bit. As a rule, the phase difference response has greater forward sensitivity than the amplitude ratio response.

[0103] In the all-round example illustrated in Figure 20, all of the plotted responses exhibit a dependence on the formation. In this example, at distances of approximately 21.3 meters (70 ft) before the layer, the amplitude ratio response begins to deviate from zero, indicating the presence of a layer of different resistivity in front of the bit. As the tool/downhole unit approaches the layer, deviations normally increase until the first antenna crosses the layer boundary, at which point some responses show maximum deviation. In the responses shown, there is a crossover point at about 3 meters (10 feet) before the layer indicating that there is a layer ahead of the drill bit. Likewise, the phase difference of the responses begins to deviate from zero at about 15.2 meters (50 feet) before the layer boundary, as shown in the right graph of Figure 20.

[0104] As illustrated in figure 20, all the responses plotted are sensitive to the layer in front of the drill bit and can be used to estimate the distance to the layer boundary in front of the drill bit. Consequently, the entire coupling tensor need not be required. For example, the balanced response can be determined using only a single slanted transmit antenna and a single slanted receiver antenna.

[0105] The distances stated above are examples, and are controlled by the T-R distances and the operating frequency used. In general, it is useful to make measurements with more than one T-R distance and more than one frequency to improve the reliability of the interpretation of the results.

[0106] In addition to the responses being plotted, the responses can be inverted to calculate, for example, the distance to the layer boundary in front of the drill bit or the formation's conductivity, anisotropy and inclination angle in front of the drill bit.

The inversion can be one-dimensional, two-dimensional or three-dimensional. A more stable and reliable inversion can be achieved by using different combinations of T-R distances and frequencies. Inversion provides accurate estimates of the distance to the layer boundary ahead of the bit when this distance is within about 2/3 of the T-R distance. However, this ratio can be improved depending on the characteristics of the formation.

[0107] In the overlooking example, the overlooking feature is clearly present as a tail feature. Change in an RCV response due to forward draft volumetrically, and can be taken separately from the formation around a transceiver system. Each diagonal link can be used independently, but in the example shown, both the TX and RCV channels are calibrated so that absolute measurements that are only sensitive to formation features can be determined. Calibration is performed because the TX output current and the RCV system, which typically includes an antenna coupled to amplifier electronics, can vary depending on temperature and other environmental factors. As illustrated in Figures 19 and 20, another combination with corresponding response to individual diagonal members involves taking the ratio ZZ/(XX+YY). Generating the measurement as a ratio between elementary links gives the advantage that it is calibrated so that no absolute measurement is necessary.

[0108] With general reference to the schematic illustration in Figure 21, one example is shown for determining the calibrated measurement ZZ/(XX+YY). In this example, the calibrated measurement ZZ/(XX+YY) can be made with a logging system using three tilted TX antennas 84 connected to a tilted RCV antenna 86. The received voltage at the receiver for each TX-RCV pair has a constant term and first and second harmonic terms. When the measurement is adjusted for rotation of the tool/downhole unit, the relative gain of the RCV channel is determined at the same time as the elementary connection. In vertical wells or near-vertical wells, the cross-coupling terms are mostly zero and thus only have constant behavior as a function of tool azimuth orientation (tool face), and therefore the individual relative gains cannot be extracted (gain can only be extracted from the first and second harmonics ). In order to measure the relative gains when the first and second harmonics are not present, a calibration of the receiving antennas can be done, for example, using test coils incorporated in the receiving antennas or other suitable electronics. In the example illustrated in Figure 11, the basic system of three transmitters and one receiver is used to determine the elementary links. In this embodiment, each transmitter and receiver pair is tilted 45° in relation to the tool's axis, and the TX-side magnetic moments are distributed azimuthally with a mutual angle of 120°.

[0109] In the example illustrated in Figure 22, the tilted directional TX and RCV antennas are shown with given magnetic dipole moments. The TX and RCV antennas stand with different azimuth angles. In this example, a receiver signal is a function of elementary coupling and system orientation in matrix form as follows:

The RCV moment vector on the right is inclined at 45° and vertical. The TX moment is oriented with an azimuth angle α in relation to the vertical. The angle φ corresponds to the rotation of the TX/RCV pair/tool.

[0110] The receiver signal can also be described as a function of elementary coupling and system orientation, where g is the transmitter-receiver channel gain as follows:

It should be noted that by applying rotation one can extract all links. For a true vertical well, only the constant term is different from zero.

[0111] The receiver signal can also be described with respect to three tilted transmitter/receiver pairs angled at 45° as follows:

The receiver moment is oriented vertically with each TX antenna at a given azimuth angle αT1, αT2, αT3 in relation to the vertical. Each TX/RCV pair has an associated gain gT1, gT2, gT3. ZZ, XX+YY and XY-YX can be calculated from the equations only if the gains or at least the relative gains are known.

[0112] Figures 23-30 show examples in graphical form of negligible sensitivity to two-step changes in resistivity with regard to distance-related attenuation and phase shift. A reasonable cutoff of 0.1dB for attenuation and 0.25 degrees for phase shift can be assumed. Estimated survey depth is dependent on the transmission frequency, which results in a shorter range at a higher frequency.

The phase shift response is deeper (for both resistivity profiles) than the attenuation resulting from the presence of a lobe. The lobe increases with frequency. Combination of attenuation and phase shift measurements at different frequencies can be used in a way similar to all-round inversion.

[0113] In Figure 23, the example is graphically illustrated for a 2kHz design with a TX/RCV distance of 18.3 meters (60 feet), with attenuation shown in the left graph and phase shift in the right graph. The graphs represent induction 18.3 meter (60 ft) 2 kHz tool sensitivity for a down-stepped resistivity profile (2 Ωm to 0.3 Ωm). A cut-off of 0.1dB for attenuation and 0.25 degrees for phase shift is used. The wider curves on the graph show the detection range. In this example, the attenuation is shown to have a range of about 12.2 meters (40 feet) in front of the lowest EM antenna. The phase shift, on the other hand, has a deeper range, but with the presence of a lobe.

[0114] In Figure 24, another example is illustrated graphically and represents induction 18.3 meter (60 feet) 5 kHz tool sensitivity for a down-stepped resistivity profile (2 Ωm to 0.3 Ωm). A cut-off of 0.1dB for attenuation and 0.25 degrees for phase shift is used. The wider curves on the graph show the detection range. In this example, the range is reduced for both attenuation and phase shift.

[0115] In Figure 25, another example is illustrated graphically and represents induction 18.3 meters (60 feet) 10 kHz tool sensitivity for a down-stepped resistivity profile (2 Ωm to 0.3 Ωm). A cut-off of 0.1 dB for attenuation and 0.25 degrees for phase shift has been used. The wider curves on the graph show the detection range. In this example, a reduction of the area is illustrated, with a lobe beginning to show in the attenuation.

[0116] In Figure 26, another example is illustrated graphically and represents induction 18.3 meters (60 feet) 20 kHz tool sensitivity for a down-stepped resistivity profile (2 Ωm to 0.3 Ωm). A cut-off of 0.1 dB for attenuation and 0.25 degrees for phase shift has been used. The wider curves on the graph show the detection range.

[0117] In Figure 27, another example is illustrated graphically and represents induction 18.3 meters (60 feet) 2 kHz tool sensitivity for an upward-stepped resistivity profile (2 Ωm to 20 Ωm). A cut-off of 0.1 dB for attenuation and 0.25 degrees for phase shift has been used. The wider curves on the graph show the detection range.

An upwardly stepped profile is equivalent to a downwardly stepped profile as in the examples illustrated and described above.

[0118] In Figure 28, another example is graphically illustrated and represents induction 18.3 meter (60 feet) 5 kHz tool sensitivity for an upwardly stepped resistivity profile (2 Ωm to 20 Ωm). A cut-off of 0.1 dB for attenuation and 0.25 degrees for phase shift has been used. The wider curves on the graph show the detection range.

[0119] In Figure 29, another example is illustrated graphically and represents induction 18.3 meters (60 feet) 10 kHz tool sensitivity for an up-stepped resistivity profile (2 Ωm to 20 Ωm). A cut-off of 0.1 dB for attenuation and 0.25 degrees for phase shift has been used. The wider curves on the graph show the detection range.

[0120] In Figure 30, another example is illustrated graphically and represents induction 18.3 meter (60 feet) 20 kHz tool sensitivity for an upwardly stepped resistivity profile (2 Ωm to 20 Ωm). A cut-off of 0.1 dB for attenuation and 0.25 degrees for phase shift has been used. The wider curves on the graph show the detection range. Similarly to the examples of downward-stepped profiles, the range illustrated is inversely proportional to frequency.

[0121] By applying the cut-off values described above and varying the T-R distance, the look-ahead range for attenuation and phase shift based on ZZ/(XX+YY) can be represented graphically, as illustrated in Figure 31. As can be seen in the graphs in Figure 31, the examples use two transmission frequencies of 1 kHz or 2 kHz. As shown, the range stagnates for longer T-R distance due to the cutoff parameters. To further increase the range, a lower frequency can be used, as illustrated in the right-hand graph in Figure 31. The graphs show examples of look-ahead range as a function of TX/RCV distance for attenuation and phase shift with respect to up-stepped and down-stepped -stepped resistivity profiles at 2 kHz and 1 kHz.

[0122] The range is also dependent on contrast ratio and resistivity level. For example, in Figure 32, graphical representations are shown at 2 kHz and 5 kHz attenuation for a down-stepped formation profile with different levels of resistivity and different resistivity contrast with respect to the highest resistivity. Each transmission frequency has an optimal resistivity level (resistivity around the bottom hole device or a resistivity peak) where the higher frequency has a more optimal range for the higher resistivity level. A greater contrast results in a better range for all frequencies. Furthermore, the resistivity peaks of 10 Ωm and 20 Ωm exhibit the best range characteristics for 2 kHz and 5 kHz respectively.

Increasing the transfer frequency enables higher resistivity. A cut-off of 0.1 dB for attenuation and 0.25 degrees for phase shift has been used. The wider curves on the graph show the detection range. In this example, the range is reduced for both attenuation and phase shift.

[0123] In logging-while-drilling applications, it may be important to be able to distinguish between a gradual change in resistivity and a gradual increase or decrease in resistivity in front of the drill bit 66. In general, with reference to Figure 33, graphical representations are shown to illustrate a preliminary distinction between step function and slope increase. The graphical representations help to describe the sensitivity of the logging-while-drilling system 44 with respect to forward sensitivity to a gradually changing versus a stepwise changing resistivity profile.

[0124] The graphical representations in Figure 33 are based on the detection range for a 9.1 meter (30 ft) gradually decreasing and stepwise decreasing resistivity profile for two resistivity contrasts of 20Ωm/2Ωm and 20Ωm/0.2Ωm. In this example, the down-stepped profile is shifted in depth to a location at half the magnitude of the slope change. The examples/representations are given for a range of TX/RCV distances (eg 9.15 meters to 30.5 meters (30 to 100 feet)) and a range of frequencies (eg 2, 5, 10 , 20, 50, and 100 kHz). The range is defined as the earliest distance to the beginning of the slope change. For each contrast, the range corresponds to a smaller proportion of the TX/RCV distance. With the long distance, the forward-looking discrimination of the slope profile versus the step profile may only be available for some frequencies. It should be noted that range variation as a function of frequency can be quite complex due to the presence of a second lobe at higher frequencies.

[0125] In Figure 34, further examples are shown in the form of graphical representations. Figure 34 shows two examples corresponding to a contrast ratio of 10 and 100 with 18.3 meters (60 feet) distance at 2 kHz. From left to right along the graphical representations in Figure 34, a 9.1 meter (30 ft) inclined profile is illustrated relative to a homogeneous formation, a down-stepped profile is located at a midpoint on the inclined profile relative to the homogeneous formation, and finally, an inclined profile is illustrated relative to the downward-stepped profile for various combinations of elemental linkages.

[0126] The logging-while-drilling system 44 also provides negligible sensitivity to a steep resistivity profile with respect to an anisotropic formation and a non-zero structural slope. As illustrated by the graphical representations in Figure 35, the formation anisotropy and relative slope, for which the predictive data collection is performed by the logging-while-drilling system 44, does not appreciably change the behavior of the diagonal members of the elemental linkage matrix. ZZ/(XX+YY) is a useful combination measurement to use in many applications. With tilt and/or anisotropy, the cross-couplings XZ and ZX are non-zero, so the usual symmetric directional measurements (ZZ+ZX)/(ZZ-ZX) * (ZZ-XZ)/(ZZ+XZ) can also be used to produce that forward-looking information.

[0127] The capability of forward looking and looking around function of the logging system as a function of structural inclination is illustrated in the graphical representations in Figure 36. In Figure 36 examples are shown for considering measurements as a function of four different structural inclinations (0°, or vertical , 30°, 60° and 90°, or horizontal). As illustrated in the graphical representations, the measurements of XX and YY have a clear horn effect in vertical wells, while the measurements of YY and ZZ are affected in horizontal wells. ZZ/(XX+YY) gives a good measurement that is valid for all angles. Such a measurement does not contain the directional information that the other directional measurements (i.e. the first and second harmonic directional measurements) have.

[0128] The forward-looking function of the logging system can also be used to determine proximity of contaminated sand for optimal coring, as illustrated by the graphical results shown in Figure 37. In this example, the forward-looking capability of the logging-underbore system 44 is used to determine the proximity and presence of a contaminated sand position just above a main reservoir so that core drilling can be carried out in the contaminated sand layer or section. In the examples represented by the graphs in Figure 37, the 2 kHz and 20 kHz examples both show sensitivity to the middle layer, but with a somewhat reduced ability to look ahead, e.g. less than half the length. As can be seen in the graphical representations in Figure 38, however, the layer thickness can be estimated with stronger effect for a current-conducting layer in contrast to an insulating layer. The various graphical representations illustrated and described above are presented to facilitate understanding of the logging method described here. However, the control system 52 can also be arranged to display the various graphs and other information on the display device 56 to facilitate analysis of a number of different underground features and properties based on data produced by means of the logging system 44 and the entire system 40.

[0129] Figures 39 and 40 show flowcharts to illustrate the process of determining a formation property ahead of bit 66 through inversion. In the first example in Figure 39, an all-round measurement is initially performed, as represented by step 88. The data is inverted for the formation around the borehole, e.g. the wellbore 42, as represented by step 90. A forward measurement can then be performed, as represented by step 92. The data obtained is inverted for a formation feature in front of the drill bit 66, as represented by step 94.

[0130] Another example is illustrated by the flowchart in Figure 40, where an all-around measurement is initially performed, as represented by step 96. A forward-looking measurement is also performed, as represented by step 98. The measurement data obtained is inverted for all formation features, as represented of step 100. It should be noted that since the inversions are based on the volumetric impact of the formation on the measurements, the ability to look ahead and the calculations require knowledge of and inversion of the formation structure and resistivity around the bottomhole unit 46. Antennas with shorter T-R distance and higher frequency (reduced survey depth) can be used to collect data and determine the formation around the bottom hole unit while not being sensitive to the forward sighting features. As illustrated by the flowchart, direct inversion can be used to invert for all survey depths simultaneously.

[0131] With reference to figures 41-43, the overlooking inversion can be divided into two categories. As represented in Figure 41, one category includes a 1D inversion. This method is useful for a wide range of applications, and the method is particularly suitable for use with vertical wells where the slope of the formation structure is close to horizontal. As an example, this inversion method can be used in applications involving pore pressure detection, drilling control, geofilling and landing within a reservoir. A second category includes a 2D/3D inversion as represented by figures 42 and 43. Applications that use this inversion method are often used in horizontal wells. For example, the method is useful for geosteering and for detecting features in front of the drill bit, such as an incoming fault or shale to be avoided.

[0132] The system and method described here can be used to improve the collection and analysis of data regarding underground areas, such as areas in front of or around a well bore. The system and method can be used to collect data for several investigation depths in desired directions to improve the understanding of a given well formation or another underground area. As described, the transmitter antennas and receiver antennas can be selected and oriented to enable radial sensitivity and/or sensitivity in front of the logging system. For example, the system may enable sensitivity in front of the drill bit 66. The location of and distance between the transmitter antenna and the receiver antenna may be selected with respect to both the parameters of a given application and the environment in which the logging operation is performed to facilitate detection of features in front of the drill bit/downhole assembly.

[0133] Accordingly, although only a few embodiments of the present invention have been described in detail above, those skilled in the art will readily realize that many modifications are possible without departing from the teachings of this invention. Such modifications are intended to be included within the scope of this invention as defined in the claims.

Claims (29)

Patent claims 1. A logging-while-drilling system for detecting and measuring one or more subsurface features and/or characteristics in front of or around a drill bit (14), comprising: a transmitter module (21) having a transmitter longitudinal axis and a transmitter antenna (41) located on or near the drill bit, the transmitter module (21) having connectors on both ends and being removably coupled into a downhole unit; a receiver module (25) having a receiver longitudinal axis and a receiver antenna (43), the receiver module (25) having connectors on both ends and being removably coupled into the downhole assembly and positioned at a separate location along the logging-under-boring system relative to the transmitter module (21) so that the transmitter antenna (41) and the receiver antenna (43) are located axially apart along the bottom hole unit, where at least one of the transmitter antenna (41) and the receiver antenna (43) is a directional antenna, and where the distance between the transmitter antenna (41) and the receiving antenna (43) is selected to be equal to or greater than the thickness of at least one reservoir layer being investigated by the logging-while-drilling system; and a control system having a processor capable of: process forecast data and/or survey data received from the logging-under-drilling system; relating the forward looking data or the looking around data to an electromagnetic coupling tensor; transforming one or more components of the electromagnetic coupling tensor into a corresponding formation parameter; and outputting the forward looking data and/or the looking around data and/or corresponding formation parameters to an output device. 2. The logging-while-drilling system according to claim 1, where the transmitter and receiver antennas (41; 43) are both directional antennas with dipole moments that cross their respective module longitudinal axes at approximately equal angles. 3. The logging-under-drilling system according to claim 1, where the transmitter and receiver antennas (41; 43) have dipole moments that cross their respective module longitudinal axes at different angles. 4. The logging-while-drilling system according to claim 1, where the transmitter antenna (41) and the receiver antenna (43) comprise magnetic dipole antennas, electric dipole antennas, or a combination of electric and magnetic dipole antennas. 5. The logging-while-drilling system according to claim 1, further comprising one or more downhole tools arranged between the transmitter module (21) and the receiver module (25). 6. The logging-while-drilling system according to claim 1, where the positions of the transmitter and receiver antennas (41; 43) have a distance based on a desired looking-over distance or a desired looking-around distance. 7. The logging-during-drilling system according to claim 1, where the measurements of one or more underground features and/or characteristics in front of or around the drill bit (14) are carried out using the transmitter and receiver antennas (41; 43) at three or more frequencies for each decade. 8. The logging-under-drilling system according to claim 1, where the measurements of one or more underground features and/or characteristics in front of or around the drill bit (14) are carried out at frequencies that meet |k|.Lε[0,1;10] , where k represents a rate coefficient calculated as k<2>=εμω<2>+iσμω, where ε represents electromagnetic permittivity, μ represents electromagnetic permeability, σ represents conductivity, and ω represents angular frequency. 9. A method for detecting and measuring one or more underground features and/or characteristics in front of or around a drill bit (14), comprising: providing a logging-while-drilling system that has: a transmitter module (21) that has a transmitter longitudinal axis and a transmitter antenna (41) located on or near the drill bit (14), the transmitter module (21) has connectors on both ends and is removably coupled into a downhole unit, a receiver module (25) having a receiver longitudinal axis and a receiver antenna (43), the receiver module (25) has couplings on both ends and is removably coupled into the downhole assembly and is positioned at a separate location along the logging-while-drilling system relative to the transmitter module (21), where at least one of the transmitter antenna (41 ) and the receiver antenna (43) is a directional antenna, and a control system that has a processor, where the transmitter antenna (41) and the receiver antenna (43) are placed apart axially along the bottom hole assembly, the distance is chosen to be equal or even less than the thickness of at least one reservoir layer being investigated by the logging-while-drilling system; process forecast data and/or survey data received from the logging-under-drilling system; relating the forward looking data or the looking around data to an electromagnetic coupling tensor; transforming one or more components of the electromagnetic coupling tensor into a corresponding formation tensor; and outputting the forward looking data and/or the looking around data and/or the corresponding formation parameter to an output device. 10. The method according to claim 9, further comprising: comparing a measured response to a calculated expected response based on a specific formation model; and determine the presence and position of one or more resistivity contrasts in front of or around the drill bit (14). 11. The method according to claim 10, further comprising using the presence and position of the one or more resistivity contrasts for geosteering, detection of layer boundaries, landing of a well bore, detection of pore pressure, positioning for core sampling, geofilling, and drill management. 12. The method according to claim 11, further comprising determining a distance between a reference point and one or more layer boundaries. 13. The method according to claim 10, wherein the comparison includes calculating a difference between the measured response and the calculated expected response. 14. The method according to claim 10, wherein the measured response is related to a component of the electromagnetic coupling tensor or a combination of components of the electromagnetic coupling tensor. 15. The method according to claim 10, wherein the calculated expected response is related to a component of the electromagnetic coupling tensor or a combination of components of the electromagnetic coupling tensor. 16. The method according to claim 9, wherein the output includes displaying on a screen and/or plotting on a tangible medium. 17. The method according to claim 9, further comprising determining formation properties selected from the group consisting of: a pore pressure, a distance to a layer boundary, a layer thickness, a formation type, a conductivity tensor, a slope angle, a slope azimuth, and a fault detection. 18. The method of claim 17, further comprising using the determined formation property for geosteering, layer boundary detection, landing a well bore, pore pressure detection, positioning for core sampling, geofilling, and drill management. 19. The method according to claim 9, further comprising calibrating the transmitter antenna (41) and the receiver antenna (43). 20. The method according to claim 9, further comprising determining a predictive sensitivity to two-step changes in resistivity with respect to distance-related attenuation and phase shift. 21. The method according to claim 9, further comprising determining a forward vision range. 22. The method according to claim 9, further comprising distinguishing between a gradual change in resistivity in front of the drill bit (14) and a gradual increase or decrease in front of the drill bit (14). 23. The method of claim 9, further comprising determining a predictive sensitivity of a resistivity profile with respect to an anisotropic formation and a structural slope that is different from zero. 24. The method of claim 9, further comprising determining the look-ahead function and the look-ahead function capability of the logging-while-drilling system as a function of structural slope. 25. The method according to claim 24, further comprising determining the proximity of contaminated sand by using the capability of the predictive function of the logging-underboring system. 26. The method according to claim 9, wherein the processing further comprises performing a 1D, 2D, or 3D inversion on the forward data. 27. The method according to claim 9, where the measurements of one or more underground features and/or characteristics in front of or around the drill bit (14) are carried out using the transmitter and receiver antennas (41; 43) at three or more frequencies for each decade. 28. The method according to claim 9, where the measurements of one or more underground features and/or characteristics in front of or around the drill bit (14) are performed at frequencies that meet |k|.Lε[0,1;10], where k represents a walking coefficient calculated as k<2>=εμω<2>+iσμω, where ε represents electromagnetic permittivity, μ represents electromagnetic permeability, σ represents conductivity, and ω represents angular frequency. 29. A method for detecting and measuring one or more underground features and/or characteristics in front of or around a drill bit (14), comprising: providing a logging-while-drilling system having: a transmitter module (21) having a transmitter longitudinal axis and a transmitter antenna (41) located on or near the drill bit (14), the transmitter module (21) has connectors on both ends and is removably coupled into a downhole unit, a receiver module (25) having a receiver longitudinal axis and a receiver antenna (43), the receiver module (25) has connectors on both ends and is removably coupled into the downhole assembly and is positioned at a separate location along the logging-while-drilling system relative to the transmitter module (21), where at least one of the transmitter antenna ( 41) and the receiving antenna (43) is a directional antenna, and a control system having a processor; process forecast data and/or survey data received from the logging-under-drilling system; relating the forward looking data or the looking around data to an electromagnetic coupling tensor; transforming one or more components of the electromagnetic coupling tensor into a corresponding formation tensor; outputting the forward looking data and/or the looking around data and/or corresponding formation parameter to an output device; and determining formation properties selected from the group consisting of: a pore pressure, a distance to a layer boundary, a layer thickness, a formation type, a conductivity tensor, a dip angle, a dip azimuth, and a fault detection, wherein the determined formation property is used for geosteering, layer boundary detection, landing of a well drilling, pore pressure detection, positioning for core sampling, geofilling, and drill management.