NO335379B1 - Method for obtaining enhanced geophysical information about the subsurface using acoustic receivers in a survey borehole - Google Patents

Abstract

The invention provides a method for designing boreholes. In one method, one or more boreholes are drilled along planned paths based in part on seismic surveys performed from the surface. An acoustic transmitter brought into such boreholes transmits acoustic signals at one or more frequencies within a frequency range at a plurality of separate locations. A plurality of substantially serially separated seismic receivers in the boreholes and / or on the surface receive signals reflected by the underground formations. The sensors may be permanently installed in the boreholes and may be fiber optic devices. The receiver signals are processed by conventional geophysical processing methods to obtain information about the underground formations. This information is utilized to update previous seismograms to obtain higher resolution seismograms. The improved seismograms are then used to determine the profiles of the production holes to be drilled. Borehole seismic imaging can then be used to further improve seismograms and to plan upcoming boreholes. Cross-well tomography can be used to further update the seismograms to control the reservoirs. Permanently installed sensors can also be used to monitor the prevalence of fracturing in nearby wells, thereby providing the necessary information to control fracture operations.

Description

The subject area of the invention.

This invention relates generally to the placement of boreholes and management of the associated reservoirs and more particularly to selectively drilling one or more boreholes to conduct seismic surveys therefrom to improve seismograms and to utilize the improved seismograms to determine the type and direction of for boreholes to develop a field. The method of the invention further concerns obtaining seismic information during drilling of the boreholes and during production of hydrocarbons in order to improve hydrocarbon production from the reservoirs. The method of the invention further concerns using the derived seismic information to automatically control petroleum production wells by using downhole calculator-based control systems.

The journal article "Crosswell seismic radial survey tomograms and the 3-D interpretation of a heavy oil steamflood" by MATHISEN, M.E. etc. in the magazine publication Geophysics, vol.60, no.3, May-June 1995 mentions several of the features as in the invention.

The patent document WO 96/21165 A1 belonging to the INSTITUTE FRANCAIS DU PETROLE; GAZ DE FRANCE, like the above-mentioned article, mentions cross-well tomography.

The patent document US 5363094 to Staron et al. also deals with cross-well tomography.

Background for the invention.

Seismic surveys are carried out from surface sites to obtain maps of the structure of underground formations. These surveys are in the form of maps (hereafter called seismograms) that show cross-sections of the earth beneath the investigated region or area. Three-dimensional ("3-D") surveys have become common over the last few decades and provide significantly better information of the underground formations compared to the previously available two-dimensional ("2-D") surveys. The 3-D surveys have significantly reduced the number of dry boreholes. However, it is still the case that because such seismic surveys are carried out from the surface, they lose resolution due to the distance between the surface and the desired hydrocarbon-bearing formations, dips in and around the underground formations, layer surface boundaries which are typically several thousand feet.

Surface seismic surveys utilize relatively low-frequency acoustic signals to carry out such surveys because such signals penetrate to greater depths. However, low-frequency signals produce lower resolution, which produces low-resolution seismograms. High-frequency signals provide relatively high-resolution layer surface delineations, but attenuate relatively quickly and are thus not used for performing seismic surveys from the surface.

Only in rare cases would an oil company drill a well without first studying the seismograms for an area. The number of boreholes and the path for each borehole are typically planned on the basis of the seismograms over the area. Due to the relatively low resolution of such seismograms, boreholes are often not drilled along the most efficient well paths. In addition, more and more complex well boreholes are now being drilled, where the location can be improved using high-resolution seismograms. Furthermore, relatively recently it has been proposed to drill boreholes along curved paths through and/or around underground formations to increase the potential recovery rate or to improve the production rate of hydrocarbons. In such cases, it is even more critical to have seismograms that relatively accurately show the layer surface boundaries or the outline of underground formations.

Typically, seismograms have been updated by a) performing borehole imaging which is typically performed while drilling a borehole and b) cross-well tomography which is performed between a number of producing wells in an area. In the case of borehole imaging, a seismic source generates acoustic signals while drilling the borehole. A number of receivers placed on the surface receive acoustic reflections from underground formation boundaries, which signals are processed to obtain more accurate layer surface information about the borehole. This technique helps to improve surface seismograms bit by bit. Data from each such well that is drilled is used for continuous updating of the seismograms. However, such boreholes are neither planned nor optimally located for the purpose of conducting underground seismic surveys. Their well paths and sizes are determined on the basis of potential hydrocarbon recovery. In the case of cross-well tomography, acoustic signals are sent between different transmitters and receivers located in producing wellbore. The effectiveness of such techniques is reduced if the wellbore holes are not optimally placed in the field. Such techniques would take advantage of well boreholes planned on the basis of improved seismograms.

During monitoring of production reservoirs, it would be useful to have information about the state of the reservoir at a distance from the borehole. Cross-well techniques are available to provide this type of information. In seismic tomography, a series of 3-D images of the reservoir are developed to provide a 4-D model of the reservoir. Such data have usually been collected by wireline methods where seismic sensors are lowered into a borehole dedicated only for monitoring purposes. Furthermore, seismic data collected in different wireline runs usually suffer from data mismatches due to differences in coupling of the sensors to the formation, where the data does not match.

The present invention addresses the above-mentioned problems and provides a method for carrying out underground seismic surveys from one or more well boreholes. These boreholes may have been drilled for the purpose of carrying out such investigations. Alternatively, permanently fixed sensors in a borehole which may even be a production well can be used to collect such data. The data from such underground surveys are used to improve the previously available seismograms. The improved seismograms are then used to plan the production boreholes. Borehole seismic imaging and cross-well tomography can be used to further improve the seismograms for reservoir management and control.

Summary of the invention.

The present invention provides a method for shaping boreholes. In one method, one or more boreholes are drilled along pre-planned paths based in part on seismic surveys carried out from the surface. An acoustic transmitter emits acoustic signals at one or more frequencies within a range of frequencies at a number of separate locations. A plurality of essentially serially spaced receivers in the boreholes and/or at the surface receive signals reflected by the underground formations. While the acoustic receivers are permanently deployed downhole, the acoustic transmitter can optionally be located permanently or temporarily downhole; or it may be located permanently or temporarily at the surface of the well. The receiver signals are processed by conventional geophysical processing methods to obtain information about the underground formations. This information is used to update previous seismograms to obtain seismograms with a higher resolution. The improved seismograms are then used to determine the profiles of the production wells to be drilled. Borehole seismic imaging can then be used to further improve the seismograms and to plan future boreholes. Information collected by tomographic surveys carried out over a period of time can be used to map changes in reservoir conditions at a distance from the boreholes and suitable control measures can be taken. Fiber optic sensors together with a light source can also be used to detect the acoustic and seismic signals.

Another embodiment of the present invention includes permanent downhole formation evaluation sensors that remain downhole throughout the production operation. These formation evaluation sensors for formation measurements can include, for example, gamma ray detection liar formation evaluation, neutron porosity, resistivity, acoustic sensors and pulsed neutrons that can sense and evaluate formation parameters in real time including important information with respect to water migration from different zones. Permanently installed fiber optic sensors can also be used to measure acoustic signals, pressure, temperature and fluid flow. These are used in seismic mapping as well as to establish and update reservoir models and in the management of hydrocarbon production.

In particular advantageous permanent downhole sensor installation involves permanently placing acoustic transmitters and receivers in an oil, gas or injection well to collect real-time seismic data. The seismic data is used for, among other purposes, to a) define the reservoir; b) define the distribution of oil, water and gas in the reservoir with respect to time; c) monitoring of saturation, dilution and movement of oil, water and gas; and d) monitoring the progress of a fracturing operation. In contrast to known forms of seismic monitoring, the data obtained by the present invention is available in real time.

Brief description of the drawings.

For a detailed understanding of the present invention, reference is made to the following detailed description of the preferred embodiment in connection with the associated drawings where like elements have become like numerical references, where: Fig. 1 shows a schematic illustration of the placement of a wellbore and associated transmitters and receivers for performing underground seismic surveys according to an embodiment of the present invention. Fig. 1a shows a receiver network for use on the surface according to an embodiment of the present invention. Fig. 2 shows a schematic illustration of the placement of a number of well boreholes and associated transmitters and receivers for carrying out underground seismic surveys according to an embodiment of the present invention. Fig. 3 shows a schematic illustration of several production well boreholes formed for the production of hydrocarbons and which utilize the information obtained from investigations carried out according to the present invention. Fig. 4 shows a schematic illustration of several wellboreholes formed for hydrocarbon production and which utilize information obtained according to the present invention, where at least one of the production wellboreholes is formed from the wellborehole formed for carrying out the underground seismic survey. Fig. 5 is a diagrammatic overview of an acoustic seismic monitoring system according to the present invention.

Detailed description of the preferred designs.

In general, the present invention provides methods for obtaining improved seismic models before drilling production well boreholes, where the drilling of the well boreholes is based at least partially on the improved seismic models and methods for improved reservoir modeling by continued seismic investigation during the life of the production well boreholes.

Figure 1 shows a schematic illustration of an example of placement of a survey borehole and receivers and source points for performing underground seismic surveys according to the present invention. For illustration purposes and to facilitate understanding, methods according to the present invention are described by means of examples and thus such examples should not be taken to be limitations. Furthermore, the methods are described with regard to drilling boreholes offshore but are equally applicable to drilling well boreholes from land-based drilling sites. In this configuration, a well borehole 10 is planned based on all pre-existing information about the structure of the underground formation. Such information typically includes seismic surveys carried out on the surface and may include information from well boreholes previously formed in the same or nearby fields. As an example, Fig. 1 shows non-hydrocarbon-bearing formations la and Ib separated by hydrocarbon-bearing formations Ila and Nb (herein also referred to as "production zones" or "reservoir"). After the well path for

once the exploratory borehole 10 has been determined, it is drilled in any conventional manner. Typically, reservoirs are found several thousand feet below the earth's surface and in many cases oil and gas are trapped in several zones separated by non-hydrocarbon bearing zones. It is preferred that the hydrocarbon-bearing formations should not be invaded by drilling fluids and other drilling activity except that which is necessary to drill well boreholes for the extraction of hydrocarbons from such formations. Therefore, it is generally preferred that the exploration well 10 be placed in a non-hydrocarbon-bearing formation such as the formation la. In addition, it is preferred that the exploration borehole be placed relatively close to and along the reservoirs.

Typically, production well boreholes are relatively large in diameter, generally more than seven inches (7") in diameter. Such large-diameter wellbore holes are expensive to drill. Exploration boreholes such as borehole 10 in the example, however, need only be large enough to accommodate acoustic receivers such as such as hydrophones, fiber optic sensors, and an acoustic source that moves within the borehole as further explained below. Such slim boreholes can be drilled relatively inexpensively in non-producing zones without regard to invasion of the formations near the borehole. In addition, relatively inexpensive fluids can be used to drill such boreholes. As mentioned before, reservoirs lie several thousand feet below the earth's surface and thus the exploratory borehole such as borehole 10 can be located several thousand feet below the earth's surface. In addition, if the exploratory borehole is not ultimately to be used for purposes that would require lining or other completion of the borehole , such a borehole can be filled with a heavy fluid (k all "kill-weight" fluid) to prevent collapse of the borehole.

When the investigation borehole 10 has been drilled, a receiver string or line 12 with a number of serially separated receivers 12a is placed along the borehole. The receiver locations 12a are preferably given equal distances and each receiver location 12a can comprise one or more receivers such as hydrophones, seismometers or accelerometers. The receivers could also be single or multi-fiber optic strings or segments, each such segment containing a plurality of discrete fiber optic sensors; in such a case, a light source and detector (not shown) is deployed in the borehole to send light energy to the sensors and the receiver the reflected light energy from the sensors and suitably placed data acquisition and processing unit is used for processing the light signals. The use of such receiver lines is known in the art and is not described in detail here. Alternatively or in addition to the receiver string 12, one or more receiver lines such as the line 14, each with a number of serially separated acoustic sensors 14a can be deployed on the seabed 16 for use in relatively shallow water. For relatively deep water applications, one or more receiver lines can be located at a relatively short distance below the sea surface 22. Receiver lines 22 are floated so that they remain at a desired distance below the sea surface. Figure 1a shows a plan view of an exemplary configuration of a set of receiver lines R1-Rn which can be placed on the surface of the earth. The receivers in each line are assigned by rij where i is the line and j is the sequential order position on line i. The receivers on adjacent lines are shown offset by half the distance between adjacent receivers.

The same fiber optic sensors could be used as an acoustic sensor and to determine other downhole conditions such as temperature, pressure and fluid flow. The use of fiber optic sensors in downhole tools is fully described in "provisional application US/60/045,354 which is hereby referred to.

We refer again to Fig. 1. To perform a seismic survey from the survey borehole 10, a seismic source (acoustic transmitter) is triggered at a first location, such as location 12s1. The acoustic signals move around the exploration borehole 10 and are reflected and refracted at layer boundary surfaces between the different formations. The reflected waves such as the waves 30 are detected at receivers 12s in the exploration borehole 12. The detected signals are transmitted to a surface control unit 70 which processes the detected signals according to known seismic processing methods. Desired information relating to the survey activity is displayed on a display panel and all desired information is recorded on a recorder. The control unit preferably comprises a calculator with a seismic data processing program for performing processing of the receiver data and for controlling the operation of the source 15.

The source 15 is then moved to the next location in the borehole 10 and the above process is repeated. When receiver lines such as lines 14 are deployed on the seabed 16, signals 32 from the underground formations are detected at the receivers 14a. The signals detected by the sensors 14a are then collected and processed by the control unit 70 in the manner previously described. When receiver lines 18 are placed lying in the sea water 20, then reflected signals shown by the lines 34 are detected by receivers 18a in lines 18. The signals received by the lines 18 are then processed by the control unit 70 in ways as described earlier. It should be noted that for this purpose of carrying out the invention any combination of receiver lines can be utilized. In addition, the source can be activated at surface locations.

In the first embodiment of the invention, the source 15 is preferably led into the exploration borehole 10 and moved to each of the source points 15si. This allows the utilization of only one source for carrying out the survey. The source 15 is preferably arranged to emit acoustic signals at any frequency within a range of frequencies. The control unit 70 is used to vary the amplitude and frequency of the acoustic signals emitted by the source 15. Because the exploration borehole is strategically located at a relatively short distance from some or all of the producing formations, a relatively high frequency signal can be used to obtain high resolution seismic maps for short distances , which is not feasible from any seismic surveys conducted from the surface. In addition, the source 15 can be oriented in any direction to emit acoustic signals in a specific direction (hereafter referred to as focused signals). This can allow true three-dimensional layer boundary information to be obtained with respect to formations surrounding the exploration borehole 10. During drilling of the borehole, cuttings from known depths can provide information about the rock structure which in turn can be used to determine relatively accurately the acoustic velocities of some of the formations surrounding the exploration borehole 10. These velocities are used during processing of the signals detected at the receiving lines, such as lines, such as lines 12, 14 and 18. This provides a more accurate outline of layer boundaries compared to surface seismic surveys which typically use estimated values of acoustic velocities for underground formations .

The information obtained from the above survey is used to update previously existing seismic models. This can be done by combining data obtained from the survey carried out from the survey borehole 10 or by any other known method. In addition to real acoustic velocities for underground formations obtained in this way can be used to update seismic models for the area.

Reference is made to Fig. 1a, where the source line defined by s1-sp is shown symmetrically placed in relation to the surface seismic lines R1-Rn. It is preferred to utilize symmetrical receiver and transmitter configurations because it simplifies data processing.

Fig. 2 shows a schematic illustration of the placement of a number of well boreholes and associated transmitter and receiver lines for carrying out underground seismic surveys according to a method of an embodiment of the invention. In this configuration, an exploration well 100 is formed along a well path based on the previous seismic and other subsurface information available. The borehole 100 has a first branching borehole 100b located above the first reservoir Ila and a second branching borehole 11b located above and along a second reservoir Nb. Other configurations for multiple surveys may be adopted based on the location of the reservoir to be developed. For example, separate boreholes can be drilled from different surface locations. An exploratory borehole can be drilled along a dip to more accurately map the dropping formation using relatively high frequency acoustic signals.

Each of the survey boreholes such as boreholes 100a and 100b is lined with a receiver line 102 and 104 respectively. To perform seismic survey from the borehole 100a, a transmitter is activated from each of the source points s. The reflected signals 106 are detected by the receivers r in line 102, any receivers in all other survey boreholes and by any receivers placed on the surface. The data from the receivers is then processed by the control unit in the manner described above with respect to Fig. 1 to obtain information about the underground formations. Seismic data can be obtained at different frequencies and by using focused signals in ways described earlier with respect to Fig. 1.

Fig. 3 shows a schematic illustration of multiple production well boreholes formed for the production of hydrocarbons by utilizing information obtained from investigations carried out according to an embodiment of the invention. Once the underground geological information has been updated, the size and location of production wells such as the wells 100, 100a and 100b are determined for the development of a region determined on the basis of the updated seismograms or underground models. The well boreholes thus desired are drilled and completed to produce hydrocarbons. It is desirable to place a number of receivers, such as receivers 202 in the borehole 200a and receivers 206 in the borehole 200b. In some cases, it may be desirable to leave the receiver line 12 in the exploratory borehole 10.1 during the lifetime of the boreholes 200a and 200b, acoustic sources can be activated at selected locations in any of the production well boreholes and in the exploratory borehole 10. Receivers in the various boreholes detect signals corresponding to the transmitted signals. The detected signals are then processed to determine the state of the various reservoirs over time. This information is then used to update reservoir models. The updated reservoir models are then used to control production from the various boreholes in the field. The updated models can be used to selectively change the production rates from any of the production well boreholes in the field, to shut down a particular well, to overhaul a particular wellbore, etc. the permanent availability of receiving lines in the exploration wellbore 10 which is relatively close to the production well boreholes 200a and 200b provides more accurate information about the underground formations than surveys carried out from the surface. However, surface seismic surveys conducted after the well boreholes have produced can still be updated with information obtained from surveys conducted using the survey borehole 10.

Fig. 4 shows a schematic illustration of multiple production well boreholes formed for the production of hydrocarbons on the basis of information obtained from investigations carried out according to an embodiment of the invention, where at least one of the production well boreholes is formed from the borehole which is made to carry out underground seismic investigation. In some cases, it may be desirable to drill an exploratory borehole which can later be used to form

production branch borehole from. Figure 4 shows the formation of an exploration borehole 300a from a common vertical well section 300. The borehole 300 is first used to carry out seismic surveys in the manner described herein and then one or more production boreholes such as well boreholes 300b and 300c are formed from the exploration borehole 300a. Additional production well boreholes such as 310 may be formed from the common borehole section 300 or from other surface locations (not shown) as desired. Receivers 302a and 312a respectively shown in boreholes 300a and 310 perform the same functions as explained above with respect to Figures 1-3.

Another aspect of the invention is the use of permanently downhole placed acoustic sensors. Fig. 5 shows a schematic representation of the acoustic seismic monitoring system as described immediately above. Fig. 5 shows in more detail a production well 410 for the production of oil, gas or the like. Well 410 is defined by the well casing 412 which is cemented or otherwise permanently placed in the soil 414 by means of a suitable cement 416. The well 410 has been completed in a known manner using production tubing having an upper section of production tubing shown at 416A and a lower part with production pipe 416B. Attached between production tubing 416A and 416B in a suitable location is the permanent acoustic seismic sensor in accordance with the present invention and is shown generally at 418. Acoustic sensor 418 includes a housing 420 with a primary flow passage 422 that communicates with and is generally aligned with the production tubing 416A and 416B. The housing 420 also includes a side passage 424 that is laterally offset from the primary flow passage 422. The side passage 424 is defined by a laterally projecting section 426 of the housing 420 and an internal partition wall 428. Located within the side passage 424 is a downhole electronics and control module 430 which is connected in series with a plurality of permanent acoustic receivers 432 (eg, hydrophones, seismometers, and accelerometers). The acoustic receivers 432 are located longitudinally along the production pipe 416 (and therefore longitudinally along the wall of the borehole) in an area of the geological formation of interest for sensing and recording seismic changes with respect to time. At the ground surface 434 is a surface control system 436 that controls an acoustic transmitter 438. As discussed, the transmitter 438 may also be located below the surface 434. The transmitter 438 will periodically emit acoustic signals into the geological formation which are then sensed by the array of acoustic receivers 432 with the resulting sensed data processed using known analysis techniques.

A more complex description of boreholes comprising permanent downhole formation evaluation sensors can be found in US 5,662,165 the entire contents of which are incorporated by reference.

As discussed in trade journals such as the article "4D Seismic Helps Track Drainage, Pressure Compartmentalization", Oil and Gas Journal, March 27, 1995, pp. 55-58, and "Method Described for Using 4D Seismic to Track Reservoir Fluid Movement", Oil and Gas Journal, 3 Apr. 1995, pp. 70-74 (both articles here fully incorporated by reference), seismic monitoring of wells over time becomes an important tool in analyzing and forecasting well production and performance. Prior to the present invention, such seismic monitoring could only be done in near real time using known wireline techniques; or on sensors placed on the outside of various forms for shallow applications (never in production wells). Examples of such seismic monitoring are described in US 5 194 590. The article "Time-lapse crosswell seismic tomogram interpretation: Implications for heavy oil reservoir characterization, thermal recovery process monitoring and tomographic imaging technology", Geophysics 60, no.3 (May/June ),pp 631-650; and the article "Crosswell seismic radial survey tomograms and the 3-D interpretation of a heavy oil steamflood", Geophysics 60, 3 (May/June), pp 651-659, the entire content of which is incorporated herein by reference. However, in accordance with the present invention, a significant advance in seismic monitoring has been achieved by installing the seismic (ie, acoustic) sensors as a permanent downhole installation in a well. A number of seismic transmitters as described in US 5,662,165 are used as sources of seismic energy in boreholes at known locations. The seismic waves detected by receivers in other boreholes provide, after appropriate analysis, a detailed three-dimensional image of a formation and fluids in the formation with respect to time. Thus, according to the invention, an operator has a continuous real-time three-dimensional image of the borehole and surrounding formation and is able to compare the real-time image with previous images to ascertain changes in the formation; and, as discussed in more detail below, this continuous monitoring can be done from a remote location.

Such imaging of fluid conditions can be used to control production operations in the reservoir. For example, a picture of the gas/water contact in a producing gas reservoir makes it possible to take preventive actions before water is produced in a well by selectively closing sleeves, gaskets, safety valves, plugs and other fluid control devices downhole where it is feared that water may be produced if preventive actions are not taken. In a steam-flooding or C02-flooding operation for the secondary recovery of hydrocarbons, steam or C02 is injected into the reservoir at selected injection wells. The steam or C02 drives the oil in the pore spaces in the reservoir in the direction of the production wells. In secondary recovery operations, it is critical that the steam or C02 does not reach the production wells: if a direct flow path for steam or C02 is established between the injection well and the recovery well (called a "breakthrough"), further "flushing" operations to recover oil will be ineffective. Monitoring the position of the steam/oil or C02/oil interface is therefore important, and by closing sleeves, gaskets, safety valves, plugs and other fluid control devices in a production well where a breakthrough is imminent, the flow patterns can be changed sufficiently to avoid a breakthrough . In addition, sleeves and fluid pressure control devices can be operated in the injection wells to affect the general flow of fluids in the reservoir. The downhole seismic data to perform the tomographic analysis is transmitted uphole by methods described in US 5,662,165 collected at the control center and transmitted to a remote location where a powerful digital calculator is used to perform the tomographic analysis in accordance with methods described in the patent and the references above.

Another aspect of the invention is the ability to control a cracking or fracturing operation. In a "frac job", fluid is injected at high pressure into a geological formation that suffers from insufficient permeability for the flow of hydrocarbons. Injection of high-pressure fluid into a formation at a well has the effect of fracturing the formation. These fractures generally propagate away from the well in directions determined by the properties of the rock and the underground stress conditions. As discussed by P.B.Wills et al in an article called "Active and Passive Imaging of Hydraulic Fracture", Geophysics, the Leading Edge of Exploration, july, pp 15-22 (incorporated herein by reference) the use of downhole geophones in a well (a monitoring well) it is possible to monitor the propagation of fractures from a well other than the well from which the fracturing is induced. The propagating fracture in the formation acts as a series of small seismic sources that emit seismic waves. These waves can be registered in the sensors in the monitoring well and on the basis of the registered signals in a number of monitoring wells the active edge of the fracture can be monitored. Having such real-time observations makes it possible to control the fracturing operation itself by using methods according to the invention.

Claims (14)

1. Procedure for obtaining geophysical information about geological formations, characterized by that it comprises the following steps: a) formation of an exploratory borehole along a predetermined well path, where part of the borehole is close to a production reservoir, and at a certain distance from the earth's surface; b) placing a first plurality of discrete seismic receivers in the exploratory borehole; c) generating seismic pulses into the geological underground formations, the seismic pulses being acoustic signals with a frequency in a frequency range; d) detecting by the plurality of seismic receivers seismic waves reflected by the geological formations in response to the generated seismic pulses, and generating signals in response to such detected seismic waves; and e) processing the generated signals to obtain geophysical information about the underground formations; and f) design of a production well hole in the base formation by using the acquired geophysical information. 2. Method according to claim 1, characterized by that the exploration borehole is shaped so that it does not intersect a hydrocarbon-bearing formation. 3. Method according to claim 1, characterized by that it further includes combining the obtained geophysical information about the underground formations with other data to obtain improved geophysical information about the underground geological formations. 4. Method according to claim 3, characterized by that the enhanced geophysical information is one of the following: i) a seismogram of the subsurface geological formations, ii) an acoustic velocity of a subsurface formation, iii) distance between the exploration borehole and a layer boundary, and iv) distance between at least two subsurface layer boundaries. 5. Method according to claim 4, characterized by that the enhanced geophysical information is a 4-D map of the underground formations. 6. Method according to claim 1, characterized by that the seismic pulses are generated by a source located at a location that is one of i) within the exploration borehole, ii) at the surface, iii) an offshore location, and iv) a secondary borehole. 7. Method according to claim 1, characterized by that it further comprises i) placing a second set of discrete seismic receivers outside the exploratory borehole; ii) detecting seismic waves reflected by geological formations in response to induced seismic pulses, at receivers in the second set of receivers, and generating signals in response to such detected seismic waves; and iii) combining the signals from the first and second sets of receivers to obtain the geophysical information. 8. Method according to claim 1, characterized by that it further includes the formation of at least one borehole in the hydrocarbon-bearing formation whose well trajectory is at least partially determined on the basis of the obtained geological formation. 9. Method according to claim 1, characterized by that it further comprises i) subsequent execution of seismic surveys to obtain secondary information about the underground formation, and ii) combination of the obtained geophysical information and the secondary geophysical information to obtain an improved map of the underground formations. 10. Method according to claim 1, characterized by that it includes generating a cross-well seismogram from the detected seismic waves. 11. Method according to claim 1, characterized by that the seismic receivers are selected from the set consisting of geophones, accelerometers, hydrophones and fiber optic sensors. 12. Method according to claim 1, characterized by that the well path is close to a producing interval, where said borehole is primarily formed to carry out seismic surveys and not for exploration or production purposes and where the seismic pulses are generated at a number of separate positions in the survey borehole. 13. Method according to claim 12, characterized by that the exploration borehole is shaped so that it does not intersect a hydrocarbon-bearing formation. 14. Method according to claim 1, characterized by that the receivers are permanently installed in the survey borehole.