WO2021137704A1

WO2021137704A1 - Virtual rvsp check shot from downhole seismic sources using seismic interferometry

Info

Publication number: WO2021137704A1
Application number: PCT/NO2020/050321
Authority: WO
Inventors: Alexander Goertz
Original assignee: Octio As
Priority date: 2019-12-30
Filing date: 2020-12-17
Publication date: 2021-07-08
Also published as: NO20191539A1; NO345672B1

Abstract

A method (300) is provided for creating a Virtual RVSP check shot or subsurface image from recordings of a borehole seismic source using seismic interferometry. The method includes reversing the positions of source and receiver for interferometry in order to redatum the wavefield recorded by a surface receiver or seafloor receiver (101) into a shallower borehole depth level, thus creating a virtual receiver at that depth level. The data (103) from the desired shallower source level is cross correlated with data (113) from all other source levels and then summed over all surface receivers (101). The Virtual RVSP check shot data (105) improves the signal-to-noise ratio of the SWD-RV SP check shot data, because data recorded at different receivers near the wellbore is combined and summed into the virtual receiver (110).

Description

TITLE: Virtual RVSP check shot from downhole seismic sources using seismic interferometry

TECHNICAL FIELD

The present invention relates to reverse vertical seismic profiling (RVSP). More particularly, the invention discloses a method and system to increase signal-to-noise ratio in seismic while drilling (SWD) data by combination of data from a multitude of receivers at surface or seafloor.

BACKGROUND OF THE INVENTION

Information about Earth’s geophysical formations is obtained using various seismic techniques. Typically, in drilling operations, a surface seismic survey is performed, in which seismic source reflects from subsurface geophysical formations and is recorded by the receivers at the surface. The problem of accurately determining the depth of target formations along a well path and associated calibration with 3D seismic images obtained from the surface is typically solved with a check shot vertical seismic profiling (VSP) acquisition. Vertical seismic profiling (VSP) uses one or more seismic source at the wellhead and an array of receivers is lowered into the wellbore/borehole and seismic waves emanating from sources near the wellhead are recorded into the receivers.

Further using the principle of reciprocity, it is also possible to obtain the same dataset by lowering sources into the wellbore and recording the waves emanating from sources excited at many depth levels in the wellbore at one or several receivers near the wellhead, a so-called Reverse vertical seismic profiling (RVSP) check shot, also known as inverse seismic profiling (IVSP) check shot.

US2008221796A1 by Doherty et al disclose 1st order free -surface multiples recorded in VSP data or reverse VSP data that are processed using a 3-C 3-D vector migration method to produce an image of the subsurface. This image produces a larger coverage than that obtained in 3-C 3-D processing of reflection data acquired in the VSP.

Further, using drill bit noise as seismic signal to produce a VSP-like dataset is not new and extensively described for example in a book by Poletto and Miranda (F. Poletto and F. Miranda, "Seismic while drilling: fundamentals of drill-bit seismic for exploration", Handbook of geophysical exploration, Elsevier, 2004). In reciprocate, the signals from the drill bit are detected at surface receivers and processed as RVSP data. This avoids having to replace the drill string in the wellbore with borehole sources or receivers which typically require lengthy and extensive interruptions of the drilling process before the well reaches its target depth.

The VSP/RVSP surveying methods are known is the prior arts. US Patent No. 6,747,915 by Calvert discloses a method of seismic imaging a subsurface formation by creating a virtual source, the virtual source method, as described in a subsequent publication (A. Bakulin and R. Calvert, “The virtual source method: Theory and case study”, Geophysics (2006) 71 (4): SI139-SI150), which applies to sources at the surface and receivers in a borehole.

Seismic interferometry is employed to redatum a seismic source excited at the surface to a receiver level positioned at depth in a borehole to create a virtual source at the position of the receiver. The redatuming is carried out by cross-correlating the data recorded at the desired virtual source level with data from all other borehole receivers and summing over all available surface shot points. Source signature deconvolution is performed to ensure uniform waveforms before summation over all shot points.

In such circumstances, interferometry technique is been used to construct virtual sources and/or virtual receivers, for which “virtual shot records” can be created for locations within the obstacles. This fills in part of the missing data, though with virtual sources only at the positions of the receivers (or, in some cases virtual receivers at positions of sources). Seismic interferometry (e.g. G.T. Schuster, "Seismic Interferometry", Cambridge University Press, 2009) can be employed to redatum seismic source excited at the surface to a receiver level positioned at depth in a borehole, to create a “virtual source” at the position of this receiver. The redatuming is carried out by cross- correlating the data recorded at the desired virtual source level with data from all other borehole receivers and summing over all available surface shot points. A source signature deconvolution is required to ensure uniform waveforms before summation over all shot points. This variant of seismic interferometry was first described by Bakulin and Calvert (A. Bakulin and R. Calvert, 2004, Virtual Source: new method for imaging and 4D below complex overburden: 74th Annual International Meeting, SEG, Expanded Abstracts, 2477-2480). US Patent No. 9,575, 193 by Vermeer and Halliday discloses a method for receiving data collected from a zone that includes a plurality of receivers and using cross-correlation of the recorded seismograms to estimate a virtual response in areas not accessible for placing seismic sources or receivers. Further PCT publication WO 2011/159803 A8 by Mateeva et al. discloses a method of synthesizing a virtual receiver at a drill bit source location by correlating the raw drill bit signal from that source position with itself for the purpose of capturing reflections off the side of the borehole from, e.g., a salt flank. The method is designed only to create virtual receivers at the same location of the source, as it works on raw uncorrelated drill bit data. In order to create a dataset where a different drill bit source level is recorded into the virtual receiver, a drill bit signal deconvolution needs to be carried out before the interferometric correlation. This aspect is described in Liu et ah, 2015 (Y. Liu et ah, "Retrieving virtual reflection responses at drill-bit positions using seismic interferometry with drill -bit noise", Geophysical Prospecting, 2015, 1-13) in which they modelled synthetic data for the hypothetical case of a horizontal borehole and further discloses that receivers need to be placed such that they cover the stationary vicinity for reflected paths.

For obtaining seismic information from the wellbore without interrupting the drilling process by using tools incorporated in the drill string is known in the prior arts. The seismo-acoustic noise emanating from a rotating drill bit is one such possible source that can be recorded by a multitude of receivers either on land or at the seafloor in the vicinity of the wellhead. Drill bit noise is random and continuous and therefore needs to be correlated with a pilot in order to obtain the representation of an impulsive source and hence the response (Green’s function) of the medium. In principle, there are three possibilities to obtain a suitable pilot for correlation: (i) mounting a sensor into the bottom hole assembly (BHA) and recording the near-source signal with the same time base than surface or seafloor receivers , or (ii) mounting a sensor at the top drive on the drilling rig and recording with the same time base, or (iii) focusing surface or seafloor recordings onto the known drill bit location using a known velocity model and stacking to extract a trace representative of the waveform emanating from the drill bit location (focused pilot). All three methodologies have been used in the past and are described in Poletto & Miranda (2004). These methods are known collectively as seismic measurement-while -drilling (seismic MWD), sometimes shortened to "seismic while drilling" (SWD).

A check shot can be obtained from such data by taking one surface or seafloor receiver near the wellhead and correlating a selected time interval of the continuous data with the pilot trace representing the same time interval. This correlation is repeated for each consecutive time interval. As the drill bit moves deeper, each time interval corresponds to a different depth interval of drilling. Typical penetration rates range from 2 to 10 m an hour, such that one meter of drilling corresponds to about 5 min to 30 minutes of data. Typical correlation lengths range from 2 to 10 minutes of data. As the penetration rate changes over time (faster in soft formations and slower in hard formations, including pauses when drill pipe is added to the string), the resulting correlated data needs to be regularized in depth. This includes discarding all time intervals in which no drilling occurred (such as when drill pipe is added) and stacking all correlated time intervals corresponding to the same depth interval. The choice of depth interval in the final regularized SWD-RVSP check shot data depends on the signal-to- noise ratio (larger depth intervals correspond to longer time intervals over which correlated data is stacked), and the wavelength of the received drill bit signals (the depth interval needs to be short enough such that the combination of drill bit positions through that depth interval are smaller than a wavelength and can still be considered a point source).

Further, there is a need for methods of geophysical prospecting which improves the accuracy of seismic migration. For that, interferometry-based acquisition and processing methods can overcome near-surface complexity and improve time-lapse seismic image applications.

US Patent No. 9,477,001 by van Groenestijn discloses a method for redatuming seismic data to any arbitrary location in the subsurface in a way that is consistent with the internal scattering in the subsurface. Further US Patent Application No. 2018/0217284 by Zhao et al. discloses a method of virtual source (VS) redatuming. The method employs time-dependent smoothing of the filtered down going seismic wavefields which is performed to generate smoothed down-going seismic wavefields. A cross-correlation is calculated between up-going seismic wavefields separated from the common receiver gather and the smoothed down-going seismic wavefields. For vertical wells, a RVSP check shot from SWD data can in principle be obtained without interferometric redatuming with only one single sensor near the wellhead. A recent example has been presented by Poletto et al. (F. Poletto et ah, "Seismic while drilling using a large-aperture ocean bottom array", SEG Technical Program Expanded Abstracts, Aug 2019, pages 5320-5324). Apart from being restricted to near-vertical wells, such data typically suffer from poor signal-to- noise ratio and may be additionally obfuscated by geological complexity in the near surface and overburden above the target. If a multitude of receivers is installed near the wellhead with for example an ocean bottom cable, a significant portion of the recorded data is not utilized for interpretation. Also, due to the radiation pattern of a drill bit source, the receiver location with the highest amplitude source signal differs for direct arrivals and reflected arrivals and may not necessarily be optimally positioned for check shot interpretation.

Therefore, it is clear that the data quality achievable with traditional approaches is limited, mainly due to two reasons: (i) only a subset of the acquired data (a near -offset node) can be used for time- domain check shot processing, and (ii) the data quality as a function of offset from the wellhead is highly variable, on the one hand due to the drill bit radiation pattern and on the other due to the noise emanating from the drilling platform, hence the “right” node has to be chosen carefully. By analysing the data quality from a multitude of nodes it became clear that this limit can be overcome if data from several nodes can be combined and summed in order to increase the signal -to-noise ratio. Hence, the present invention overcomes the problems in the prior arts. The present invention provides a method to improve the signal-to-noise ratio of SWD-RVSP check shot data, because data recorded at different receivers near the wellbore is combined and summed into one virtual receiver.

SUMMARY OF THE INVENTION Embodiments of the present invention provide a method and a system of reverse vertical seismic profiling (RVSP). The method includes reversing the positions of source and receiver for interferometry in order to redatum the wavefield recorded by a surface receiver or seafloor receiver into a shallow borehole depth level, thus creating a virtual receiver at that depth level. The data from the desired shallower source level is cross-correlated with data from all other source levels and then summed over all surface or seafloor receivers.

In one embodiment of the present invention provides a method of creating Virtual RVSP check shot from drill bit seismic data using seismic interferometry. The method includes (i) placing a multitude of receivers into the vicinity around a wellhead, where that vicinity is centered around the projection of stationary paths to the surface or seafloor, (ii) obtaining a pilot trace for correlation, (iii) selecting suitable correlation length and combining individual raw records into recordings of the length and time intervals with actual drilling, (iii) correlating all recordings with respective to the pilot, (iv) selecting suitable depth interval and combining the correlated time intervals to the depth intervals respectively using driller’s depth to obtain a correlated RVSP dataset, (v) performing first break picking in the correlated RVSP dataset, (vi) separating wavefield which is an estimate of down-going and up-going wavefield along borehole trajectory, (vii) deconvolution for removing variations in a source signature, near -receiver variations, and removing multiple arrivals, (viii) selecting a shallower downhole source position for recoding data in the receiver at the surface or the seafloor receiver positions for redatuming using the seismic interferometry, (ix) muting the data at a selected source position a short time after the first break pick to obtain the pilot for correlation, (x) applying an interferometric redatuming through cross - correlation of the data from all other downhole source positions with the pilot from the shallower downhole source position, and summing a result of the all surface or seafloor receiver positions laid in the stationary vicinity for a desired wavefield, and (xi) resulting a virtual receiver data excited at the all downhole positions and recorded at the position of the virtual receiver, where the virtual receiver data contains both a direct wavefield and a reflected wavefield, or only the reflected wavefield and the result is a “SWD-RVSP check shot. In another embodiment of the present invention, the Virtual RVSP check shot data improves the signal -to-noise ratio of the SWD-RVSP check shot data, because data recorded at different receivers near the wellbore are combined and summed into the virtual receiver.

In another embodiment of the present invention, the virtual receiver check shot data contain both the direct wavefield and the reflected wavefield, or only the reflected wavefield and the result is called a “SWD-RVSP check shot”. The virtual receiver check shot data is independent of the overburden velocity model and wavefield distortions that may arise from geological complexities in the near surface are taken out of the data, which in turn may increase the signal -to-noise ratio.

In another embodiment of the present invention, the method provides increasing the signal-to- noise ratio in the SWD data is by combination of the data from the multitude of receivers at the surface or seafloor.

In another embodiment of the present invention, the seismic interferometry is performed for redatuming an impulsive seismic source excited in the subsurface to the receiver level positioned at surface or seafloor, to create the virtual receiver at the position of the source. The redatuming is carried out by cross-correlating the data recorded at the desired virtual receiver level with data from all other borehole source and summing over all available surface shot points.

In another embodiment of the present invention, the stationary paths are found by finding the direct wavefield or the reflected wavefield ray paths connecting physical and the virtual source and projecting these ray paths to the surface receiver.

In another embodiment of the present invention, selecting the suitable depth interval and combining the correlated time intervals to the respective depth intervals using driller’s depth to obtain the correlated RVSP dataset.

One objective of the present invention is of covering an area around the stationary paths that is large enough not only to include the stationary vicinity (first Fresnel zone), but also provides a means of averaging over the source radiation pattern in order to mitigate the effect of low signal amplitudes around nodal planes of the source radiation pattern.

One another objective of the present invention is increasing the signal -to-noise ratio though combination of all data measured at this multitude of receivers into a virtual downhole receiver location.

In another embodiment of the present invention, separate subsets of receivers are chosen to focus on the direct wavefield or the reflected wavefield.

In another embodiment of the present invention, processing and interpreting the virtual check shot data is done either in the time or depth domain for near vertical or deviated wells. Data can also be processed in the depth domain, i.e., by migrating the resulting virtual receiver data instead of doing a time-domain “check shot” interpretation. The latter will become necessary if wells are highly deviated (up to horizontal) and the subsurface has strong lateral variations.

Other variations, embodiments and features of the present disclosure will become evident from the following detailed description, abstract and claims.

BRIEF DESCRIPTION OF THE DRAWINGS

The various features described herein will be best understood from the attached drawings, taken along with the following description, in which like numerals generally have been used to represent similar elements, and in which: Fig. 1 shows Virtual RVSP method using principle of interferometrically redatuming a multitude of surface receivers into one shallower “virtual” downhole receiver level for the purpose of obtaining the wavefield between a virtual receiver and all source points in accordance with an embodiment of the present invention;

Fig.2 shows Ray diagram of relevant arrivals for interferometry in accordance with an embodiment of the present invention; and

Fig.3 is a block diagram of a method for creating Virtual RVSP check shot from drill bit seismic data in accordance with an embodiment of the present invention.

DETAILED DESCRIPTION

The present invention will now be described more fully hereinafter with reference to the accompanying drawings in which a preferred embodiment of the invention is shown. This invention may, however, be embodied in many different forms and should not be construed as being limited to the embodiments set forth herein. Rather, the embodiments are provided so that this disclosure will be thorough, and will fully convey the scope of the invention to those skilled in the art. With reference to Figs.l and 2, the present invention is described herewith in details. Embodiments of the present invention provide methods and systems for Virtual RVSP check shot from drill bit seismic data using seismic interferometry.

The term “Virtual source" refers to a point for which actual seismic data, i.e. seismic signals from an actual source to actual receiver, are measured and mathematically manipulated so as to generate a data set that simulates signals from that point to the actual receiver, even though there is no actual source at that point.

The term “Virtual receiver" refers to a point for which actual seismic data, i.e. seismic signals from an actual source to actual receiver, are emitted and mathematically manipulated so as to generate a data set that simulates signals from an actual source position to that point, even though there is no actual receiver at that point.

Seismic survey equipment synchronizes the sources and receivers, records a pilot signal representative of the source, and records reflected waveforms that are detected by the receivers is pilot trace. As illustrated in Fig.l, in one embodiment, the present invention provides a method for creating Virtual RVSP check shot from drill bit seismic data. As illustrated in Fig.1 , for assembling a RVSP check shot in the described fashion from drill bit seismic data, only one receiver R_k 101 near the wellhead is required. The signal-to-noise obtained in the assembled check shot is therefore limited and lower than it could be if a multitude of receivers in the vicinity of the wellbore are utilized. Typically, a multitude of receivers at various offsets from the wellhead are deployed to record drill bit seismic signals.

In one preferred embodiment, as illustrated in Fig.l, the RVSP method includes reversing the positions of source and receiver for interferometry in order to redatum the wavefield recorded by a surface or seafloor receiver R_k 101 into a shallower borehole depth level, thus creating a “virtual receiver” 110 at that depth level. The recorded data R_ka (103) from the desired shallower source level Sa is cross correlated with data R_kp (113) from all other source levels and then summed over all surface receivers R_k 101. As illustrated in Fig. 1 downhole source Sp 102 is a continuous drill bit signal, the drill bit pilot correlation needs to be carried out beforehand, possibly followed by an additional deconvolution step to ensure a uniform waveform across the receiver array before summation.

The virtual RVSP check shot data Dap _ls 105 calculated using the formula provided below:

In another embodiment, the result is a virtual RVSP check shot Dap 105 combining the wavefields emanating from all downhole drill bit source levels Sp 102 as if it were recorded in one shallower virtual receiver 110 level. The resulting virtual RVSP check shot can be processed in the same fashion as a zero-offset VSP to invert for seismic velocities along the wellbore and assemble a reflection dataset in two-way time (TWT corridor) for the purpose of identifying target reflections ahead of the drill bit. Further, as depicted in Fig.1 , in another embodiment of the present invention these are the aspects taken into consideration; Firstly, Stationary paths of the wavefield summation in which the “virtual” wavefield obtained via interferometry can only be correctly reconstructed if it includes so-called stationary paths. That is, the ray paths between the physical source -receiver combinations to be summed over need to pass through the location of the virtual receiver 110.

Secondly, source radiation pattern is considered: A downhole source Sp 102 (whether drill bit or other) is not omnidirectional and has a specific radiation pattern 112 indicated in Fig.1. Depending on the type of drill bit and the deviation of the borehole, it can therefore happen that the emergence angles of stationary paths are falling into a nodal plane of the source radiation pattern 112 and the resulting signal energy is low. It can also happen that the signal energy is different for direct and reflected waves. In particular, the process will require no knowledge of the velocity model.

Further as illustrated in Fig.2 is the result obtained in form of Ray diagram of direct 201 and reflected 202 arrivals for interferometry in another embodiment of the present invention.

The method for creating Virtual RVSP check shot from drill bit seismic data is described herein in details with steps as illustrated in Fig.3. In step 301, is placing a multitude of receivers into the vicinity around a wellhead such that it is centered around the projection of stationary paths to the surface or seafloor. Stationary paths are found by finding the (direct or reflected) ray paths connecting the physical and virtual source and projecting these ray paths to the surface receiver Rk. In step 302, is obtaining a pilot trace for correlation with at least one of these methods (downhole accelerometer, top drive accelerometer or focused pilot). In step 303, is selecting suitable correlation length and combine individual raw records into recordings of that length and keeping only time intervals with actual drilling. In step 304, is correlating all recordings with respective pilot.

Thereafter, in step 305, is selecting suitable depth interval and combine correlated time intervals to respective depth intervals using driller’s depth to obtain a correlated RVSP dataset. In step 306, includes First break picking in correlated RVSP dataset. In Step 307, includes Wavefield separation which is an estimate of the down-going and up-going wavefield along the borehole trajectory can be obtained by various means. A typical approach would be to align the data along the first-break picks and obtain an estimate of the down-going wavefield with a median filter and an estimate of the up-going wavefield by subtracting the median-filtered (down-going) wavefield from the aligned total wavefield.

In step 308, is deconvolution for the purpose of removing variations in the source signature, near receiver variations, and removing multiple arrivals. Different approaches can be applied here. A typical approach would be to design a Wiener filter based on the down-going wavefield which is estimated via a median filter along the first break picks.

In step 309, is selecting a shallower downhole source position to which data recorded at all surface or seafloor receiver positions is to be redatumed to using seismic interferometry.

In step 310, is muting the data at the selected source position a short time after the first break pick to obtain a pilot for correlation In step 311, includes applying interferometric redatuming through cross-correlation of data from all other downhole source positions with the pilot from the shallower downhole source position, and summing the result over all surface or seafloor receiver positions which are determined to lie in the stationary vicinity for the desired wavefield (direct or reflected). The stationary vicinity needs to be chosen large enough such that it reaches beyond possible nodal planes of the source radiation pattern. The cross correlation can be either (i) between the pilot and the unseparated wavefield from other source levels to obtain a virtual check shot containing both down-going and up-going waves between the virtual receiver and all other downhole source levels, or (ii) between the pilot and the estimated up-going wavefield from other source levels to obtain a virtual check shot containing mainly energy that has been reflected upwards from heterogeneities between the downhole source levels and the virtual receiver. The area covered by surface or seafloor receivers containing the stationary vicinity for both wavefields may be different, as depicted in Fig. 2.

In step 312, is resulting virtual receiver data will be equivalent to a dataset as if an impulsive source with a signature corresponding to the autocorrelation of the interferometric pilot trace had been excited at all downhole positions and recorded at the position of the virtual receiver (the shallower downhole source level). It may contain either the total direct and reflected wavefield, or only the reflected wavefield. This result is called a “SWD-RVSP check shot”.

In step 313, the SWD-RVSP check shot data will be subject to standard check shot VSP-type processing which may entail additional deconvolution operators to shape the wavelet to a desired form, residual wavefield separation steps, correction for the deviation of the borehole, alignment of the data to Two-way time (corridor) and applying a corridor stack. This step is applicable in near-vertical wells.

Alternatively, and preferably for highly deviated wells, steps 309 to 311 can be repeated with different virtual receiver positions to obtain a dataset as if virtual receivers had been recorded at all downhole source positions. Such data could be transformed to an image of the subsurface using pre-stack depth migration under the assumption of a velocity model for the subsurface below the shallowest depth level used as virtual receiver position.

In one advantage of the present invention, the method of Virtual RVSP check shot as described above is used to improve the signal -to-noise ratio of SWD-RVSP check shot data, because data recorded at different receivers near the wellbore is combined and summed into one virtual receiver 110. The improvement in signal-to-noise should in theory be equal to the square root of the number of receivers deployed at the surface or seafloor. The virtual receiver 110 also combines data over a larger source emergence angle range and is hence less subject to effects of the source radiation pattern such as nodal planes. Data from different surface or seafloor receivers can be combined differently to redatum the direct and reflected wavefield and hence honoring the associated amplitude differences arising from the source radiation pattern. The expected Signal -to-Noise ratio increase will be strongest for vertical wells. In another advantage of the present invention is the resulting virtual receiver check shot data is independent of the overburden velocity model and wavefield distortions that may arise from geological complexities in the near surface are taken out of the data, which in turn may increase the signal-to-noise ratio. Portions of the wavefield which are forward scattered in the overburden and near surface may additionally contribute positively to the effective aperture contained in the virtual receiver data. The virtual receiver check shot data is processed so as to provide information selected from the group consisting of: images of the formation of interest, measurement of a property of the formation of interest, measurement of distance to the formation of interest, and combinations thereof.

In another advantage of the present invention, the method is not restricted to any particular well shape but works equally also for highly deviated wells as long as the surface or seafloor area covered with receivers includes the stationary wave paths. These stationary wave paths can be found by extrapolating the borehole trajectory between virtual receiver and drill bit source to the surface following Snell’s law.

In another advantage of the present invention is providing increased signal-to-noise ratio in SWD data by combination of data from a multitude of receivers at the surface or seafloor.

In another advantage of the present invention is ability to separately focus on direct and reflected wavefields traveling between physical drill bit sources and the virtual receiver by a combination of wavefield separation and selecting different subsets of surface or seafloor receivers, depending on the respective stationary paths. In another advantage of the present invention is that the method can replace the acquisition of a wireline VSP. In another advantage of the present invention is that the data required to apply the method can be acquired independently of the drilling operation and does not cost any rig time. Hence, this method is cost effective.

The foregoing description of embodiments of the invention has been presented for purposes of illustration and description. It is not intended to be exhaustive or to limit the invention to the precise form disclosed, and modifications and variations are possible in light of the above teachings or may be acquired from practice of the invention without departing from the scope of the invention. The embodiments were chosen and described in order to explain the principles of the invention and its practical application to enable one skilled in the art to utilize the invention in various embodiments and with various modifications as are suited to the particular use contemplated.

Claims

1. A method (300) for obtaining seismic information from the wellbore without interrupting the drilling process by using reverse vertical seismic profiling (RVSP) acquisition, using a sub surface source as seismic signal, where the signals from the sub-surface source are detected at surface receivers (301), arranged into, and processed as RVSP gathers (305 - 308), and interferometrically redatumed (311) to construct virtual records along the wellbore (309), characterized in that all data measured at the multitude of receivers are divided into suitable time periods representing a specific source position (303), deprived of the complex drill-bit source signature (304) using a suitable pilot (302) before being re-combined into a virtual receiver ( 110) resulting in a virtual “SWD-RVSP” check shot (312) of enhanced signal-to-noise ratio from which interpretations of the layers ahead of the wellbore can be extracted.

2. The method of claim 1, wherein the RVSP method (300) is performed, which is reversing positions of the source and the receiver for the interferometry in order to redatum the wavefield recorded by the surface receiver or the seafloor receiver into the shallower depth level, thus creating the virtual receiver (110) at that depth level.

3. The method of claim 1, wherein the RSVP method (300) is repeated at different virtual receiver levels to create a multifold dataset for depth imaging.

4. The method of claim 3, where the created multi-fold multi-level virtual receiver dataset is transformed into an image of the subsurface below the shallowest virtual receiver (110) level using only the portion of a velocity model underneath the shallowest virtual receiver level.

5. The method of claim 1, wherein the downhole source is of an impulsive type such that no pilot correlation is required.

6. The method of claim 1, wherein the desired wavefield is a direct wavefield (201) or reflected wavefield (202) or both.

7. The method of claim 1, wherein the virtual receiver data contains both the direct wavefield (201) and the reflected wavefield (202), or only the reflected wavefield and the result is the “SWD- RVSP check shot” (312).

8. The method of claim 1, wherein the effects of a complex overburden between surface/seafloor receivers (101) and the virtual receiver level (110) has been removed from the resulting virtual receiver data without knowledge of the overburden velocity model

9. The method of claim 1, wherein the source signature deconvolution is performed to ensure uniform waveforms before summation over all shot points (308).

10. The method of claim 1, wherein the downhole source (102) is a continuous drill bit signal.

11. The method of claim 1, wherein the stationary paths are found by finding the direct wavefield (201) or the reflected wavefield (202) ray paths connecting physical sources and the virtual receiver (110) and projecting these ray paths to the surface receiver (101).

12. The method of claim 1, wherein the pilot trace (302) is obtained from either downhole accelerometer, top drive accelerometer or focused pilot.

13. The method of claim 1, wherein selecting the suitable depth interval and combining the correlated time intervals to the respective depth intervals using driller’s depth to obtain the correlated RVSP dataset (305).

14. The method of claim 1, wherein the cross correlation (311) can be either (i) between the pilot and unseparated wavefield from the other source levels to obtain the virtual check shot containing both down-going and up-going waves between the virtual receiver and the all other downhole source levels, or (ii) between the pilot and the estimated up-going wavefield from the other source levels to obtain the virtual check shot containing mainly energy that has been reflected upwards from heterogeneities between the downhole source levels and the virtual receiver.

15. The method of claim 1, wherein the SWD-RVSP check shot data is further subject to standard check shot VSP-type processing (313), the standard check shot VSP-type processing is an additional deconvolution operator to shape a wavelet to a desired form, residual wavefield separation steps, correction for a deviation of the borehole, alignment of the data to Two-way time (corridor) and applying a corridor stack.

16. The method of claim 1, wherein the Virtual RVSP check shot data improves (105) the signal -to-noise ratio of the SWD-RVSP check shot data, because data recorded at different receivers near the wellbore is combined and summed into the virtual receiver.

17. The method of claim 1, wherein the Signal -to-Noise ratio increase will be strongest for vertical wells.

18. The method of claim 1, wherein resulting virtual receiver check shot data (105) is independent of an overburden velocity model and wavefield distortions that may arise from geological complexities in near surface are taken out of the data, which in turn may increase the signal-to-noise ratio.

19. The method of claim 1, wherein increasing the signal-to-noise ratio in the SWD data is by combination of the data from the multitude of receivers at the surface or seafloor.