NO330545B1 - Method for generating and detecting directional signals during drilling and acoustic system transported in a borehole to determine a characteristic of the formation - Google Patents

Abstract

The present invention provides a method and apparatus for use in an acoustic logging tool conveyed in a borehole in a foundation formation to determine a characteristic of the formation. The method comprises using a first acoustic source to generate an acoustic signal in the base formation at a first frequency. Another acoustic source separate from the first acoustic source is used to generate an acoustic signal in the base formation at a different frequency that is different from the first frequency. An acoustic receiver is used to receive a third acoustic signal indicating said characteristics. The third acoustic signal has a frequency substantially equal to a difference between the first frequency and the second frequency. The third acoustic signal is produced by a non-linear interaction between the first signal and the second signal in part of the basic formation.

Description

TECHNICAL AREA

The present invention is directed to the area of geophysical investigations and more particularly to a method for using a seismic source to generate and collect directional signals in a wellbore during drilling, as well as an acoustic system transported in a borehole to determine a characteristic at the formation

TECHNICAL BACKGROUND

Acoustic wave information is used by the oil industry to investigate and evaluate the earth's subsurface in the search for and evaluation of valuable subsurface minerals and mineral reservoirs. Acoustic waves are generated and recorded during oil well logging. This is called sonic or acoustic logging. The sonic wave measurement carried out in wellbore is typically the formation's compressional slowness (the reciprocal value of velocity). However, other acoustic wave types can also be measured, e.g. shear waves and Stoneley waves.

Prior art acoustic wave applications have been used to help oil and gas producers better evaluate their reservoirs and maximize hydrocarbon recovery. A wide range of downhole and crosswell geophysical applications provide data to analyze reservoir properties near the wellbore and ahead of the drill bit for both exploration and field development applications.

Sonic downhole tools are e.g. used for acquisition of a traveling or three-dimensional seismic profile (VSP). Downhole three-component seismic receivers can be run in combination to simultaneously collect high-quality VSP three-component data for detailed structural and stratigraphic reservoir imaging and integration with available surface seismic and well logging data.

Conventional seismic borehole services such as velocity surveys and vertical seismic profiles provide a means of calibrating surface seismic data sets as well as well logs, and also for imaging subsurface geological structural features. Seismic-while-drilling (SWD) data collection is a method that uses the drill bit as an energy source in the wellbore to collect downhole seismic data in real time during drilling without using any special downhole instrumentation. Seismic cross-well imaging techniques are used to evaluate the continuity of reservoir units between wells.

Three-dimensional vertical seismic profile (3D-VSP) methods can be used to improve complex reservoir evaluation with conventional three-dimensional seismic survey datasets. 3D VSP services provide oil and gas producers with an advantage in reservoir characterization. High-resolution 3D-VSP data can be integrated with three-dimensional surface seismic data to provide detailed descriptions of subsurface formation properties and identification of reservoir components, which is otherwise not possible with surface seismic data alone.

Correlation of time data and depth data provides detailed, structural reservoir models that can help reduce hazards and costs in field evaluation and development. Integration of borehole seismic, surface seismic and borehole log data is an important step in producing an accurate reservoir model. Advanced borehole seismic anisotropy analyzes provide accurate velocity models and improved subsurface imaging. Hydrocarbon reservoirs are buried under an extended overburden consisting of shale and shale-bedded sediments that are often anisotropic. Three-dimensional VSP surveys are an excellent means of detecting anisotropy in subsurface formations.

US patent 6,440,075 to Averkiou describes an ultrasonic diagnostic imaging system and a method for performing non-linear echo signal imaging with harmonic and intermodulation product components (sum or difference frequency). Both the harmonic and intermodulation products are produced by non-linear effects in tissue or contrast agents and both are preferably separated from the basic transmitting components of the echo signals by means of pulse inversion processing. The use of both types of nonlinear components can improve the signal-to-noise ratio of the ultrasound images, and the two types of components can be mixed or used in different regions of an image to offset the effects of depth-dependent attenuation.

US patent 3,979,724 to Silverman et al., is directed to a method for determining the position of the drill bit. A Stoneley wave is produced at the surface and propagates through the fluid in the drill string and produces a seismic signal when it reaches a discontinuity in the fluid path at the bit.

Another device used in connection with a drill string is described in US Patent 6,478,107 to Birchak. A compressible fluid is stored in a number of chambers inside the cervix. An inlet valve is opened to allow the pressure in a chamber to build up to the pressure in the sludge. The inlet valve is then closed and an outlet valve allows the pressurized mud to flow into the annulus between the weight pipe and the borehole to thereby generate a pressure wave. This arrangement does not depend on the conversion of a Stoneley wave into an acoustic signal.

US Patent 4,993,001 to Winbow describes a method of generating acoustic waves from Stoneley waves for cable applications. A rotary valve tube wave source is used to generate swept frequency Stoneley waves which are injected into a wellbore. A transducer comprising an elongate body which mainly fills the wellbore and has a predetermined shape is positioned at a selected position in the hole.

US Patent 6,175,536 to Khan describes a method for determining a degree of acoustic nonlinearity in a foundation formation from seismic signals sent into the formation from one wellbore and received from the formation in another wellbore. The seismic signals include two selected discrete frequencies. The method includes spectral analysis of the received signals, determination from the spectral analysis of the occurrence of a frequency representing a sum of the two selected frequencies, and determination of a relative amplitude for the sum frequency in relation to the amplitudes of the two selected discrete frequencies. In a particular embodiment, the method includes determining the occurrence of a frequency in the spectral analyzes of the signals representing the difference between the selected discrete frequencies, and determining the occurrence of harmonic multiples of one of the two selected discrete frequencies.

US 5521882 discloses an apparatus and a method for determining a

indication of non-linear properties for a formation at a borehole. An acoustic tool is used in the borehole to generate a first and second acoustic signal of different frequencies. As a result of non-linearities in the formation, mixing of the first and second signals will result in a third signal with a frequency corresponding to the difference between the frequencies of the first and second signals. The difference is detected and used to determine formation properties.

US 6456566 mentions an acoustic system and a method for examining hydrocarbon reservoirs.

There is a need for an efficient method for generating directional sound wave energy in a wellbore. (More important in relation to the solution material here). The present invention satisfies this need.

SUMMARY

The present invention provides a method and a device for using an acoustic logging probe transported into a borehole in a basic formation to determine a characteristic of the formation. The method comprises generating a directional acoustic signal indicative of a characteristic of the formation by using: (i) a first acoustic source array to generate a first acoustic signal in the underlying formation at a first frequency; (ii) a second acoustic source array for generating a second acoustic signal in the base formation at a second frequency different from the

first frequency;

An acoustic receiver array is used to receive the directional acoustic signal. The directional acoustic signal has a frequency equal to the difference between the first frequency and the second frequency and the method further comprises the step of determining a characteristic of the formation by means of a semblance of the directional signal.

The present invention also provides an acoustic system transported into a borehole in a basic formation to determine a characteristic of the formation. The system comprises: a) a signal generator adapted to generate directional acoustic signals by means of: (i) a first acoustic signal generator array adapted to generate a directional acoustic signal in the base formation at a first frequency; (ii) a second acoustic signal generator array arranged to generate a directional acoustic signal in the base formation at a second frequency about

is different from the first frequency; and

(b) an acoustic receiver array adapted to receive the directional acoustic signal having a frequency equal to the difference between the first

the frequency and the second frequency; and

(c) a processor adapted to determine a characteristic of the formation by means of a semblance of the directional signal.

Other advantageous features will emerge from the associated independent patent claims

BRIEF DESCRIPTION OF THE DRAWINGS

The present invention and its advantages will be better understood with reference to the following detailed description and the attached drawings, in which: fig. 1 illustrates a schematic diagram of a drilling system with a drill string including an acoustic sensor system according to the present invention;

fig. 2 illustrates a block diagram of the most important wellbore elements in the system shown in fig. 1;

fig. 3A illustrates the frequency spectrum of two frequencies and their sum and difference frequencies;

fig. 3B illustrates an embodiment of the present invention that forms a low frequency directional acoustic beam directed at an acoustic boundary; and

fig. 4 illustrates the use of statistical distribution of the reflected signal's coherence values for detection, highlighting and discrimination of the signal of interest.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

The present invention provides a method and a system for using an acoustic logging tool transported in a borehole in a basic formation to determine a characteristic of the formation. A directional low frequency acoustic beam can be formed to provide acoustic detection of spacing and formation characteristics using two high frequency sources in a wellbore environment. Stoneley waves can also be used as a secondary source for the low-frequency acoustic energy at a remote distance from an original source. Embodiments of the invention may include similarity processing to detect and emphasize the signal of interest.

In general, the present invention provides a method and a system for use during drilling boreholes. The drilling system includes a drill string with a subassembly in the borehole that includes a drill bit at the lower end and a number of sensors and measurement-while-drilling (MWD) devices, including an acoustic MWD system with a first set of acoustic sensors to request tune the formation acoustic velocity while drilling the borehole, and another set of acoustic sensors to determine the layer boundaries using the acoustic velocity measurements taken by the first set of acoustic sensors. A wellbore computer with associated storage is arranged to calculate various operating parameters in the wellbore, to determine formation characteristics and parameters, to map the formation around the subassembly in the wellbore, to update stored models and data as a result of the calculated parameters and to assist the operator with navigating the drill string along a desired well-hole trajectory. The computer may have one or more processors for determining acoustic signal characteristics and parameters.

The drilling system may also include devices for determining formation resistivity, gamma radiation intensity in the formation, drill string inclination and drill string azimuth, nuclear porosity in the formation and formation density. The drill string may contain other MWD devices known in the art to provide information about the subsurface geology, wellbore conditions, and operating parameters of the mud motor, such as differential pressure across the mud motor, torque, and condition of the bearing assembly. Selected data is transferred between the sub-device in the wellbore and the calculation device on the surface via a two-way telemetry system. The computing device on the surface sends signals to the subdevice in the wellbore to control certain desired operations and also to process the received data according to programmed instructions to improve the drilling operations.

Fig. 1 shows a schematic diagram of a drilling system 10 with a well-hole unit containing an acoustic sensor system and the surface devices according to an embodiment of the present invention. As shown, the system 10 includes a conventional derrick 11 erected on a derrick deck 12 which supports a rotary table 14 which is rotated by a main drive device (not shown) at a desired rotational speed. A drill string 20 including a drill pipe section 22 extends downward from the rotary table 14 into a borehole 26. A drill bit 50 attached to the drill string at the lower end crushes the geological formations as it is rotated. The drill string 20 is connected to a hoisting device 30 via a drive pipe joint 21, a swivel and a line 29 through a pulley system 28. During the drilling operations, the hoisting device 30 is operated to regulate the weight of the drill bit and the rate of penetration of the drill string 20 into the borehole 26. The operation of the lift device is well known in the field and is therefore not described in detail here.

During drilling operations, a suitable drilling fluid (commonly called "mud") 31 from a mud pit 32 is circulated under pressure through the drill string 20 by a mud pump 34. The drilling fluid 31 passes from the mud pump 34 into the drill string 20 via a pressure equalization device 36, a fluid line 38 and the drive pipe joint 21. The drilling fluid is led out at the lower end 51 through an opening in the drill bit 50. The drilling fluid circulates up through the hole in the annulus 27 between the drill string 20 and the drill hole 26, and exits into the mud pit 32 via a return line 35. A series of sensors (not shown) is preferably deployed on the surface according to methods known in the art to provide information on various drilling-related parameters, such as fluid flow rate, bit weight, hook load, etc.

A surface control unit 40 receives signals from the wellbore sensors and devices via a sensor 43 located in the fluid line 38 and processes such signals according to programmed instructions delivered to the surface control unit. The surface control unit displays desired drilling parameters and other information on a display device/monitor 42, which information is used by an operator to control the drilling operations. The surface control unit 40 contains a computer, a storage of data, a data recording device and other peripheral devices. The surface control unit 40 also includes models and processes data according to programmed instructions and responds to user commands entered through suitable devices, such as a keyboard. The control unit 40 is preferably arranged to activate alarms 44 when certain unsafe or undesirable operating conditions occur.

A drilling motor or mud motor 55 connected to the drill bit 50 via a drive shaft

(not shown) arranged in a storage unit 57, the drill bit 50 rotates when the drilling fluid 31 is passed through the mud motor 55 under pressure. The bearing unit 57 supports the radial and axial forces of the drill bit, the downward thrust force on the drill bit and the reactive, upward load from the applied weight of the bit. A stabilizer 58 connected to the bearing unit 57 acts as a centering means for the lower part of the mud motor unit.

In the preferred embodiment of the system according to the invention, the subassembly 59 in the wellbore (also called the bottomhole assembly or "BHA") which contains the various sensors and MWD devices for providing information about the formation and drilling parameters in the wellbore and the mud motor, is connected between the drill bit 50 and the drill pipe 22. The downhole device 59 preferably has a modular construction so that the different devices are sections that can be connected together so that the individual sections can be replaced when desired.

Reference is still made to fig. 1 where the bottom hole device also preferably contains sensors and devices in addition to the sensors described above. Such devices include a device for measuring the formation resistivity near and/or in front of the drill bit, a gamma radiation device for measuring the formation's gamma radiation intensity, and devices for determining the inclination and azimuth direction of the drill string. The formation resistivity measuring device 64 is preferably connected above the lower emergency stop module 62, which provides signals from which the resistivity of the formation near or in front of the drill bit 50 is determined. A resistivity measuring device is described in US Patent No. 5,001,675, which is assigned to the owner of the present application, and which is hereby incorporated by reference. This patent describes a double propagation resistivity (DPR) device with one or more pairs of transmitter antennas 66a and 66b separated from one or more pairs of receiver antennas 68a, and 68b. Magnetic dipoles are used which operate in the medium and lower high frequency spectrum. During operation, the emitted electromagnetic waves are disturbed as they propagate through the formation surrounding the resistivity device 64. The receiving antennas 68a and 68b detect the disturbed waves. Formation resistivity is derived from the phase and amplitude of the detected signals. The detected signals are processed in a wellbore circuit preferably located in a housing 70 above the mud motor 55, and are transmitted to the surface control unit 40 using a suitable telemetry system 72.

The inclinometer 74 and the gamma radiation device 76 are preferably located together with the resistivity measuring device 64 to respectively determine the inclination of the part of the drill string that is close to the drill bit 50 and the gamma radiation intensity of the formation. However, any suitable inclinometer and any suitable gamma radiation device may be used for the purpose of the present invention. In addition, an azimuth device (not shown) such as a magnetometer or a gyroscope device can be used to determine the azimuth of the drill string. Such devices are known in the field and are therefore not described in detail here. In the embodiment described above, the mud motor 55 transmits power to the drill bit 50 via one or more bellows shafts running through the resistivity measurement device 64. The bellows shaft enables drilling fluid to pass from the mud motor 55 to the drill bit 50.1 an alternative embodiment of the drill string 20, the mud motor 55 can be engaged during the resistivity measurement device 64 or at any other suitable location.

The wellbore assembly according to the present invention preferably includes a MWD section 78 containing a nuclear formation porosity measuring device, a nuclear density device and an acoustic sensor system located above the mud motor 64 in the housing 78 to provide information useful for evaluating and testing subsurface formations along the borehole 26. The preferred embodiments of the acoustic sensor system are described later with reference to figures 3a and 3b. The present invention can use any of the known formation density devices. US Patent No. 5,134,285 owned by the present patent applicant, and which is hereby incorporated by reference, describes a formation density device that uses a gamma radiation source and a detector that can be used in the system according to the present invention. During use, emitted gamma radiation from the source enters the formation where they interact with the formation and are attenuated. The attenuation of the gamma rays is measured using a suitable detector, from which the density of the formation is determined.

The porosity measuring device is preferably the device that is generally described in US patent no. 5,144,126, which belongs to the present patent applicant and which is hereby incorporated by reference. This device uses a neutron emission source and a detector to measure the resulting gamma rays. During use, high energy neutrons are emitted into the surrounding formation. A suitable detector measures the neutron energy delay due to interaction with hydrogen and atoms present in the formation. Other examples of nuclear logging devices are described in US patent nos. 5,126,564 and 5,083,124.

The above-mentioned devices send data to the telemetry system 72 in the well-hole, which in turn transmits the received data to the surface control unit 40. The well-hole telemetry also receives signals and data from the surface control unit 40 and sends such received signals and data to the correct well-hole devices. The present invention preferably uses a mud pulse telemetry technique to communicate data from the wellbore sensors and devices during drilling operations. A transducer 43 placed in the mud supply line 38 detects the mud pulses in response to the data transmitted by the wellbore telemetry device 72. The transducer 43 generates electrical signals in response to the mud pressure variations and transmits such signals via a conductor 45 to the surface control unit 40. Other telemetry techniques such as electromagnetic and acoustic techniques or any other suitable technique, may be used for the purposes of the present invention.

Fig. 2 shows a functional block diagram of the main elements in the wellbore module 59 and further illustrates the data communication paths between the various system elements. It should be noted that fig. 2 only illustrates an arrangement of the elements and a system for data communication between them. Other arrangements can be used just as effectively for the purpose of the invention. The sensors for determining the operating conditions in the wellbore and the state of the downhole device are appropriately designated Si - Sj, the acoustic sensor system is designated with reference number 160 while the rest of the MWD devices in the wellbore, such as the nuclear, electromagnetic, directional and similar, are designated with di - dm. The sensors Si - Sj, the MWD devices di - dm and the desired acoustic sensor system 160 are arranged inside the wellbore module in the desired manner. During operation, a predetermined number of discrete data points fed from the sensors and MWD devices are stored in a buffer storage which, in FIG. 2, is included as a separate part of the storage capacity of the computer 150. Alternatively, the buffer storage may comprise a separate element (not shown).

Sensor response relationships or "models" for the acoustic sensor system and other sensors in the wellbore module are preferably stored in a storage 148. These models are determined mathematically and/or by measuring responses from the sensors in a known test formation. In addition, other reference data such as data defining the target formations to be drilled, seismic data, displacement well data, are preferably stored downhole in the bearing 148. A two-way data and command signal communication is provided between the computer 150 and the bearing 148. The responses from the sensors Si - Sj, di - dm and 160 are sent to the computer 150 where they are transformed into parameters of interest or response as described below. The downhole electronics for processing signals downhole and for performing other communications include the computer or control unit 150, storage 145 and 146 and other desired components, such as signal processors, amplifiers, etc. (not shown). For the sake of simplicity, the use of such components is known in the field, and is therefore not included in fig. 2. The use of these components is further described in US patents 6,427,124 and 6,023,443 to Dubinsky et al. (Applicant: Baker Hughes), which patents are incorporated in their entirety by reference.

Reference is still made to fig. 2, where the parameters of interest are sent to the surface via the upward telemetry path 127 or stored in the storage 146 for subsequent retrieval to the surface. Since the acoustic sensor system 160 and other sensors 152 and dimer are located axially along the downhole device, their responses do not correspond to the same measurement point in the borehole 26 (see Fig. 1). Prior to combining or correlating the data from different sensors, the computer 150 shifts the data to a common depth point. The different devices di - dm also do not necessarily have the same vertical resolution. Vertical resolution adjustment is therefore performed by the computer 150 before combining or correlating measurements from different sensors.

Once the depth-shifted and resolution-adjusted data are calculated, the parameters of interest are then passed to the downhole portion of the telemetry system 142 and then transmitted to the surface by means of an appropriate uplink as conceptually illustrated by the broken line 127. The power source 144 supplies power to the telemetry element 142, the computer 150, the bearings 146 and 148 and associated control circuits (not shown). Information from the surface is transmitted over the downward telemetry link conceptually illustrated by the broken line 129, to the downhole receiver element in the telemetry unit 142, and is then sent to the data storage unit 148 for subsequent use.

A preferred embodiment of the present invention provides a method for using an acoustic logging tool transported into a borehole in a basic formation to determine a characteristic of the formation. The method comprises using a first acoustic source to generate an acoustic signal in the base formation at a first frequency. The first acoustic source may be a high frequency (HF) transmitter array. Another acoustic system, which can also be a high-frequency transmitter group, is separated from the first source and is used to generate an acoustic signal in the base formation at another frequency which is too different from the first frequency. An acoustic receiver is used to receive a third acoustic signal (a resultant of the first and second sources) indicative of the formation characteristic. The third acoustic signal has a frequency substantially equal to a difference between the first frequency and the second frequency. The third acoustic signal is produced by a non-linear interaction between the first signal and the second signal in a part of the base formation.

The present invention provides for forming a directional, low-frequency, acoustic beam bundle for acoustic distance determination, formation property determination or other applications for seismic during drilling by using two high-frequency sources in the borehole environment. One of the problems in the area of seismic data collection during drilling is to form a focused, directional signal at relatively low frequency (LF) in the direction of interest. Low frequency is considered 1 kHz and lower. This is a significant disadvantage when using low-frequency sources as a primary source of the acoustic energy, since the source must have a relatively large aperture to provide adequate directivity to be effectively used for SWD applications.

The method and system according to the present invention enables the use of two (or more, preferably grouped) high-frequency (HF) sources to form a low-frequency beam in the direction of interest. Due to the natural non-linear effects in the formation, the combination of these signals will provide a low frequency signal at both the differential low frequencies and the summing frequency which are high. If e.g. frequencies of two HF sources are 70 kHz and 71 kHz respectively, the result of non-linear interaction will produce signals at 1 kHz (a useful LF component) and at 141 kHz (a less useful HF component, which will quickly spread in the formation due to the natural acoustic energy loss). Fig. 3A schematically illustrates frequency spectra for two frequencies fl, f2 together with their sum (F sum = || f1 + f2 ||) and difference

(F difference = || f1 - f2 ||) frequencies. In addition to the difference frequencies, other non-linear resonances related to the difference frequencies can also be generated. By applying an amplitude or frequency modulation to include a variable frequency acoustic drive circuit (eg using a swept signal with one or both sources) in conjunction with the original HF signals, the natural non-linearity of the rock is highlighted and increase the collected information. An advantage of using two HF sources is that it is easier to focus acoustic energy towards a spe-

cial direction using a high-frequency source (with a range of tens of kHz). The center frequency of these sources is chosen based on the expected penetration depth of the primary HF signals, as the difference of these frequencies should equal a desired low frequency for the resulting signal, which is then used for acoustic ranging or other SWD applications.

The direction of the acoustic beam for each of the two sources is chosen in such a way that the beam intersects each other at a certain distance from the borehole. Fig. 3B illustrates an embodiment of the present invention which constitutes a directional, low-frequency acoustic beam directed into a formation near a wellbore or toward an acoustic boundary 103. Placed on a section of a downhole device 105 or other suitable position on a drill string , a first acoustic source or signal generator, T1, emits a first acoustic signal, f 1 , into the base formation near a borehole. Another acoustic source or signal generator, T2, emits another acoustic signal, f2, into the underlying formation near a borehole. The resulting low-frequency acoustic energy signal F-difference will penetrate the formation in the direction of the center line 101 between the directions of the two HF signals, a first frequency f1 and a second frequency f2. An acoustic receiver (not shown) is used to receive the third frequency F difference which is produced by a non-linear interaction between the first signal f1 and the second signal f2 in the basic formation.

There are several patents on the use of acoustic transmitters and receivers in an MWD device to provide information on the position and orientation of layer boundaries near the drill bit. See e.g. US Patent 6,084826 to Leggett (Applicant: Baker Hughes Incorporated) and 5,678,643 to Robbins (Applicant: Halliburton,). These describe the use of high frequency acoustic signals to determine acoustic formation rates. The high-frequency signals used for speed determination do not have a particularly deep penetration into the underground formations. The present invention, on the other hand, provides low-frequency signals that exhibit less absorption that can be used to determine the position and orientation of layer boundaries.

As mentioned above, a main problem with the generation of low-frequency signals is that the source must have a relatively large aperture in order to provide suitable directionality for use in seismic applications during drilling. When both the wedge and the receiver are at substantially the same position on the downhole device, it can be difficult to obtain image information in certain directions.

In another preferred embodiment, the method and system according to the present invention can use a secondary source at a distance from and separated from a primary source position to take into account the geometric problem. The second source is an acoustic discontinuity in the energy propagation path. The primary source produces an acoustic signal in the casing (or in the annulus between the casing and the base formation). A Stoneley wave is produced in the casing (or in the annulus between the casing and the underlying formation) and propagates away from the source with relatively low attenuation. Whenever there is a discontinuity in the propagation path (eg hole size variation, formation change, obstructions inside the casing), part of the Stoneley wave is reflected and part of it is radiated into the formation as an acoustic wave. This radiated energy is a secondary wave sent into the underlying formation, which can provide the correct geometry for imaging layer boundaries.

The present invention provides several types of adjustable propagation path discontinuities. One type of discontinuity is the bottom of the hole, which both reflects and radiates acoustic energy. Other controllable propagation path discontinuities may also be used, such as a structure inside the cervix produced by a diaphragm or wings on the outside of the cervix to introduce a constriction in the cervix produced by a membrane or fins on the outside of the cervix to introduce a constriction in the annulus. For obvious reasons, no type of constriction can be permanent because a permanent constriction would interfere with the flow of drilling mud or production operations.

The present invention provides for the use of the Stoneley wave as a secondary source of low frequency acoustic energy at a remote distance from the original source (for (SWD) applications). Stoneley waves are seismic waves that generally propagate along an interface. Stoneley waves are always possible at solid/fluid interfaces and under limited conditions at solid/solid interfaces. Stoneley waves are surface waves in a borehole and are sensitive to formation permeability. The Stoneley wave (or more commonly used "pipe wave") is usually considered in seismic applications as a destructive guided wave in the borehole, which interferes with the signals of interest. As provided for in this application, certain features of the Stoneley wave are advantageously used for SWD applications. The following features of the Stoneley wave are used to SWD: 1) It is a guided, low-frequency wave (in the region of about 1 kHz) that propagates along the borehole over large distances with la woe loss; 2) Every obstacle in the propagation path (eg, hole size variation, formation change, or other sudden geometric or property changes along the borehole) causes a pipe wave reflection or other energy distribution to occur in the borehole. Parts of the acoustic energy are beamed into the information at these locations and can therefore be used to "look" into the formation to detect features; 3) The signature and frequency of the Stoneley wave can be controlled by the original acoustic source and/or is measurable at points where energy is distributed or changes direction.

These properties allow partial redirection of the acoustic energy to radiate energy at remote distances separately from the original source by using various mechanisms to effectively control the annulus area (e.g., a controlled diaphragm, fin, or other discontinuity). A naturally strong obstacle to the Stoneley wave is the bottom of the hole; therefore, significant acoustic energy will be radiated into the formation surrounding the bottom of the wellbore. This can be used to "look ahead" in SWD applications.

Statistical distribution of the reflected signal's coherence value (ie a histogram of the coherence values) can be used to detect and highlight the signal of interest. Even when an array of receivers distributed along a borehole is used to detect a low-magnitude reflected acoustic signal (eg a reflection from an acoustic boundary in the formation), it can still be a challenge to detect and/or correctly identify the reflection. There are two main tasks in connection with this: (1) a very poor signal-to-noise ratio for the signal of interest, and (2) the presence of many other reflections of different nature in the borehole, which will interfere with the signal of interest.

Although there are several techniques used for wave separation in conventional seismic data processing, the method according to the present invention solves the problem from a different angle. All the signals collected by means of the receiver group are mainly classified based on the distribution curve for the coherence values produced by group processing (e.g. similarity processing or other coherence analysis of signals such as cross-correlation or eigenvector analysis). It has been observed that reflections of different nature in a population of reflection events are characterized by different mean values for coherence. When therefore all coherence values are plotted as a histogram on a diagram (horizontal axis with coherence values and vertical axis with the frequency of occurrence of these values), one can observe clear populations of signals that are differently grouped around different coherence value maxima.

Fig. 4 illustrates statistical distribution of the reflected signal's coherence value for detection and enhancement of the signal of interest, and discrimination among different reflection types for acoustic borehole data in this example represents the signals with low coherence value (typically below 0.3, e.g. reflection- population no. 1) mainly reflections from an acoustic boundary in the formation. Signals with higher coherence values (greater than 0.3-0.4, or e.g. reflection population no. 2) represent different reflections in the borehole.

By sorting the signals based on these different criteria, the weak reflections of interest can be identified. Reflections from lithological boundaries within the formations near the borehole "behave" differently, i.e. have different statistical distribution characteristics compared to events originating from acoustic boundaries in a borehole. These different characteristics can be exploited. Adding a third dimension to the histogram (eg arrival time) and presenting the distribution plot as a three-dimensional curve improves signal detection discrimination. Alternatively, the data can be windowed in time to determine and improve the types and positions of acoustic events, and this can be based on previous knowledge of formation boundaries and geometries. The method and system of the present invention provides a processor to determine similarity and further discrimination of formation boundaries and lithologies. Additional material on acoustic energy discrimination is described in US patents 6,427,125 and 6,023,443 to Dubinsky et al. (Applicant: Baker Hughes), which patents are hereby incorporated by reference in their entirety.

Claims (9)

1. Method for using an acoustic logging tool transported in a borehole in a basic formation to determine a characteristic of the formation, characterized by: (a) generating a directional acoustic signal indicating a characteristic of the formation by using: (i) a first acoustic source array for generating a first acoustic signal in the base formation at a first frequency; (ii) a second acoustic source array for generating a second acoustic signal in the base formation at a second frequency different from the first frequency; (b) using an acoustic receiver array to receive the directional acoustic signal, wherein the directional acoustic signal has a frequency equal to the difference between the first frequency and the second frequency; and (c) determining a characteristic of the formation using a semblance of the directional signal. 2. Method according to claim 1, further comprising using the similarity appearance maxima to determine the characteristic of the formation. 3. Method according to claim 1, where the formation characteristic includes a formation boundary. 4. Method according to claim 1, where the directional acoustic signal is selected from the set consisting of (i) a compression wave, and (ii) a shear wave. 5. Method according to claim 1, wherein at least one of the first acoustic signal and the second acoustic signal further comprises acoustic signals with variable frequency. 6. Acoustic system transported in a borehole in a basic formation to determine a characteristic of the formation, characterized in that the system comprises (a) a signal generator arranged to generate directional acoustic signals by means of: (i) a first acoustic signal generator array arranged to generate a directional acoustic signal in the base formation at a first frequency; (ii) a second acoustic signal generator array adapted to generate a directional acoustic signal in the base formation at a second frequency if different from the first frequency; and (b) an acoustic receiver array adapted to receive the directional acoustic signal having a frequency equal to the difference between the first frequency and the second frequency; and (c) a processor adapted to determine a characteristic of the formation by means of a semblance of the directional signal. 7. System according to claim 6, further comprising a processor arranged to determine the formation characteristic from similarity appearance measurements of the directional acoustic signal. 8. System according to claim 6, where at least one of the first acoustic signal generator row and the second acoustic signal generator row further comprises an acoustic drive circuit with variable frequency arranged to generate the acoustic signals. 9. System according to claim 6, further comprising a processor arranged to determine the formation characteristic, where the formation characteristic comprises at least one of: (i) a formation boundary, (ii) abnormal pore pressure and (iii) a fault.