Method for multifold vertical seismic profile data acquisition and processing

Abstract: A seismic layout technique and a processing technique for providing better data acquisition relative to salt domes which utilizes a line of sources (s₁-S₄) in a selected pattern opposite a salt flank (10) from a well bore, and a plurality of spaced receivers (R₁-R₄ are disposed along the well bore for coaction with energy from said plural source location to record an array of multi-fold data. The data is then processed to establish a pseudo-source point (12) along the well bore in relation to each of the receiver points to enable subsequent CDP processing of the data thereby to establish a vertical common reflection point outline of the vertical flank of the salt dome.

Description: The present invention relates to acquiring seismic acoustic data and more particularly to acquiring and processing multifold vertical seismic profile data in order to accurately image vertical interfaces, such as the flank of a salt dome. Prior art has produced several methods that attempt to image the flank of a steeply dipping interface, such as that of a salt dome. However, there are serious limitations in the practical effectiveness of these techniques (i.e. a good salt flank image is rare). Currently, vertical seismic profile (VSP) imaging of a salt flank is accomplished using either an offset geometry (single source, many receivers) or a walkby geometry (multiple sources, few receivers). The data is processed using a ray tracing Vertical Seismic Profile to Common Depth Point (VSP-CDP) transformation or using a special migration program. Both techniques require a detailed geologic model to accomplish the processing. In addition, some methods to image nearly vertical interfaces require the use of both downhole sources and receivers when imaging vertical or nearly vertical interfaces. When sources and receivers are used together with multifold processing techniques, both sources and receivers may be located on the surface (conventional seismic data acquisition), or the source may be located on the surface and the receiver may be located below the surface in a wellbore (vertical seismic profile), or both the source and receiver may be located below the surface. Some examples are contained in United States Patent numbers 2,718,930 ( Bazhaw ), 4,627,036 ( Wyatt ) and 4,509,149 ( Ruehle ). United States patent number 2,718,930 titled "Method of Deep Well Surveying" ( Bazhaw ) outlines a borehole seismic technique designed to help delineate the flanks of a salt dome, reef or other nearly vertical reflector or interface. A string of geophone receivers is laid out within the borehole, and a seismic source is employed in the borehole adjacent the vertical seismometer spread. The seismic waves move laterally from the borehole to the salt and back to the receivers, imaging the salt surface. United States Patent number 4,627,036 titled "Vertical Seismic Profiling" ( Wyatt ) relates to a technique in which vertical seismic profile data is transformed into surface seismic data by mapping segments of the VSP seismic data into surface seismic data time configuration. The transformation results in data which is more easily interpreted with respect to determining subsurface structure because the data is stacked and because the data is in a more conventional form. This technique transforms conventional Vertical Seismic Profile (VSP) data, acquired using a long offset source, into the equivalent of surface seismic data. A very large offset is required for this method to operate accurately. By mapping VSP data into equivalent surface seismic data, the multifold common-depth-point (CDP) procedure may be used to enhance data quality. This manipulation is often referred to as the VSPCDP stack. United States Patent number 4,509,149 titled "Directional Long Array for Logging Vertical Boundaries" ( Ruehle ) relates to a logging sonde that has directivity control of multiple sources and receivers in linear arrays. Each of the sources produces acoustic pulses which are delayed by a time delay between the sources to direct acoustic energy at an angle such that the resulting acoustic wave strikes a vertical formation orthogonally. The reflections of the acoustic pulses are detected with a linear array of receivers. The acoustic pulse detected by each receiver is delayed by an amount such that the total differential moveout for a reflected directional wave is zero. Methods which are demonstrative of multifold processing techniques which are currently in use in the art are United States patent numbers 3,867,713 ( Tegland et al.), 4,241,429 ( Bloomquist et al.) and 4,467,460 ( Johnson ). United States patent number 3,867,713 titled "Multifold Seismic Exploration Over Purposefully Crooked Traverses" ( Tegland et al.) relates to a processing technique in which seismic impulses are generated successively at locations uniformly spaced along traverse segments which regularly cross a median line. The segments are of a length equal to an integral multiple of the spacing between the locations. Seismic waves resulting from each impulse are detected at a set of the locations. This set of locations bears the identical traverse relationship to its shot point where the impulse giving rise to the detected waves is generated as every other set of locations bears to its shot point. Preferably, the detected signals are stacked on a common depth point basis to portray regularly patterned multifold areal subsurface structure. United States patent Number 4,241,429 titled "Velocity Determination and Stacking Process from Seismic Exploration of Three Dimensional Reflection Geometry" ( Bloomquist et al.) relates to a method in which linear, multiple fold, common depth point sets of seismograms with three dimensional reflection geometry are used to determine the dip and strike of the subsurface reflecting interfaces and the average velocity of the path of the seismic energy to the reflecting interface. The reflections in each set appear with time differences on a hyperbola with trace spacings determined by the source receiver coordinate distance along the lines of exploration. The offset of the apex of this hyperbola is determined from a normal move-out velocity search of the type performed on two dimensional CDP sets. This search identified the correct stacking velocity and hyperbola offset which are used to determine dip, strike and average velocity. United States patent number 4,467,460 titled "Seismic Data Acquisition Method" ( Johnson ) relates to a method for locating seismic pulse sources to simplify multifold processing. This method is primarily concerned with coupling that occurs in reception of acoustic pulses by geophones or other acoustic pulse receivers. The field locations of seismic shot points are chosen to produce partial multifold data, the static correction equations of which are at least partially coupled. The seismic cross-sections resulting therefrom are substantially improved. EP-0206457 describes a method for segregating and stacking vertical seismic profile data wherein the offset difference between the well location and the position of the source is divided into equal segments. VSP moveout corrected data are placed in CRP bins and stacked. US-A-2021943 describes a method of profiling a generally vertical interface of a salt dome using seismic sources and receivers located in a wellbore. The preamble to claim 1 is based on this citation. According to the present invention, there is provided a method of acquiring and processing vertical seismic profile data so as to image a generally vertically extending interface comprising the steps of: generating seismic acoustic pulses by a seismic source; placing acoustic pulse receivers in a spaced-apart relation within a wellbore to receive said seismic acoustic pulses; receiving said seismic acoustic pulses that have been reflected from said interface to obtain a total travel time from said seismic source to said acoustic pulse receivers; characterised in that: said seismic source is a surface seismic source, and said wellbore is located between said interface and said seismic source, such that said acoustic pulses to be reflected at said interface and then received by said receivers pass through said wellbore before arriving at said interface; and in that said method further comprises the steps of: determining a first break time when said seismic acoustic pulses generated by said seismic source pass through said wellbore toward said interface; and subtracting said first break time from said total travel time to isolate acoustic travel from the wellbore to the interface and back to pulse receivers in said wellbore, effectively to convert said vertical seismic profile data to pseudo horizontal line data having a two way travel time. The present invention provides a method whereby the flank of a steeply dipping interface may be imaged using offset surface acoustic pulse sources and downhole acoustic receivers while still being able to take advantage of multifold processing techniques to enhance data quality. Normally, a near offset will be used when such interface is shallow and a far offset will be used when such interface is deep. In the method of the present invention, acoustic pulse sources are located on a side of the acoustic pulse receivers opposite that of the location of a steeply dipping interface, such as the flank of a salt dome. Acoustic pulses are generated and a first break time is determined when the pulses first pass the acoustic receivers on their way to the vertical interface. A total travel time is obtained when the pulses are reflected by the vertical interface and travel back to the acoustic pulse receivers. A two way travel time is calculated from a pseudo seismic source location to the receivers by subtracting the first break time from the total travel time. The data obtained on the basis of the two way travel time may then be processed as conventionally acquired seismic data. An example of a method in accordance with the invention will now be described, by way of example only, with reference to the accompanying drawings, wherein: Figure 1 is a representation of seismic data acquisition system. Figure 2 is a two dimensional view of a depth model of a steeply dipping interface and a wellbore. Figure 3 is transformed view of Figure 2 where the data acquisition line is rotated to provide a horizontal perspective. Figure 4 is a seismogram along side the depth model of the illustration of Figure 2. The present invention provides a new vertical seismic profile (VSP) acquisition geometry and processing technique which will image the flank of a steeply dipping or nearly vertical formation such as flank of a salt dome. The acquisition geometry and processing technique of the present invention requires no initial geologic model for processing and, in fact, gives a first estimate of the geologic model required for the usual processing. The unique orientation of the resulting common midpoint gather, along with the high source/receiver multiplicity, results in a seismic image of the salt face that is superior to that obtainable from currently available vertical seismic profile technology. The method of the present invention may be used either on land or offshore. However, the process of the present invention is particularly described with respect to a marine endeavor utilizing a source boat to emphasize its effectiveness. In marine data acquisition, the seismic sources may be moved to a plurality of locations, easily providing a plurality of shot points for each position in a well at which a receiver or receivers may be located. A seismic boat without a seismic streamer occupies many source locations while, for example, a three-component receiver is stationary at one depth in the well. The sources are occupied in a line or pattern opposite the salt flank from the well. At a speed, such as twelve knots, forty-eight source points could be spread over one mile (with six seconds listening time) in less than five minutes, the time currently spent at each VSP level. Slower source boats may lead to fewer source locations per traverse, or a longer recording time per receiver level. The technique could be applied onshore using more than one seismic source. The seismic boat may generate acoustic pulses at many source locations and may be repeated for many receiver depth locations from the bottom of the well to near the top of the well. As the receiver is moved up to the next successive level, the source boat can simply turn one hundred eighty degrees and shoot in the direction from which it came. Source positions can be binned, as is currently done for 3-D (three dimensional) seismic shooting. The data acquired by this method is edited, filtered, deconvolved and the upgoing and downgoing wavefields are separated. First break times for each of the source-receiver combinations are selected. A trace may be associated with each combination of sources and receivers. With each source-receiver combination, the following steps may be performed. A source-receiver combination which has the same source location but a receiver location which is shallower or at the same level is identified from other traces to provide a first break time. A new trace may be created for the present source-receiver trace. This new trace is the given trace with the first break travel time for the source-receiver combination, found above from the other traces, subtracted. The new trace is associated with an offset which is the distance between the two receiver locations. A basement is determined for this trace which is the midpoint between the two receiver locations. The new trace may then be output and displayed. These steps may be repeated for all source-receiver combinations that has the same source location but a receiver location that is shallower or at the same level. Finally, these same steps may be repeated for every source receiver combination that has a different source location. The resulting traces may now be processed as an ordinary seismic line, i.e., perform statics, velocity analysis, normal moveout (NMO), stacking, migration etc.. Using the new geometry, each reflection point is sampled at several offsets. The increased redundancy provided by the multiple offsets improves the quality of the imaging of the reflectors. The transformation from the VSP geometry to the CDP geometry does not require a detailed geological model. In contrast to other methods, the imaging improves as the dip of the salt flank increases. Figure 1 shows the acquisition geometry. Four source locations are marked S₁ through S₄ and four receiver locations are marked R₁ through R₄. The raypaths are illustrated as curved due to a mild vertical velocity gradient. As a ray travels from a source S₁ to salt flank 10 and reflects to a receiver R₁, it passes through the well bore at S ' / 1. Thus, the point S ' / 1 serves as an equivalent source location. As position S ' / 1 will be occupied by a receiver at some time in the VSP survey, then the travel time from S₁ to S ' / 1 will be the first break time for that receiver. This first break travel time can be subtracted from the travel time for the complete path from S₁ through S ' / 1 to point 12 on salt flank 10 and then to R₁. The result is the travel path from S ' / 1 to salt flank 10 and reflected back to R₁ as shown by the solid line. The resulting trace obtained by this procedure is equivalent to having a source at S ' / 1 and a receiver at R₁. If this procedure is followed for every trace, then the result is equivalent to having a line of sources S ' / 1 through S ' / 4 and a line of receivers R₁ through R₄ along the vertical well bore. By rotating the figure by ninety degrees (see Figure 3), it can be seen that the geometry is the same as that of an ordinary surface seismic line with the well bore on the "surface" and the salt flank a dipping "horizontal" bed. Thus the VSP can be converted into an equivalent CDP geometry. Referring now to Figure 2, a depth model with which the method of the present invention may be demonstrated is illustrated. In order to test the feasibility of the acquisition and processing a synthetic model was generated using a ray trace modeling package. The model consisted of four flat layers 14, 16, 18 and 20, a salt layer 22 and a salt dome 24 with a steeply dipping flank 26 (eighty degrees). The velocities used and also some of the ray paths for salt flank 26 are identified in Figure 2. Source S₁ is illustrated as having raypaths 28 and 30 reflected from flank 26 and received by receivers R₁ and R₂ respectively. Source S₇ is illustrated as having raypaths 32 and 34 reflected from flank 26 and received by receivers R₁ and R₂ respectively. The ray paths in the diagram are straight for convenience. The actual modeling used raypaths as determined by Snell's law at each interface. The results of transforming the VSP geometry to the CDP geometry are illustrated in Figure 3. Here the time required to travel the dashed portion of the ray path (i.e. a first break time) has been subtracted, leaving only the solid part of the ray paths as a two way travel time path. The dashed portions of raypaths 28 and 30 from source S₁ have been subtracted, making points S ' / 1 and S '' / 1 pseudo source points for the solid portions of raypaths 28 and 30 detected by receivers R₁ and R₂ respectively. Similarly, the dashed portions of raypaths 32 and 34 from source S₇ have been subtracted, making points S ' / 7 and S '' / 7 pseudo source points for the solid portions of raypaths 32 and 34 detected by receivers R₁ and R₂ respectively. The correct time may be determined by first determining the geophone location where the ray path crossed the well bore on the way from the source to salt flank 26. The first break time for that location is subtracted from the time recorded by the receiving geophone. Since the location of salt flank 26 is not known, the correct first break time cannot be determined directly. In order to compensate for this unknown, all possible first break times are subtracted, and the redundancy of common depth point (CDP) stacking reduces inaccuracies which may be present. The traces that result are sorted into CDP (or common midpoint) gathers and constant velocity stack analyses are generated. After velocities were picked for several depths, the resulting velocity function was used to correct for normal moveout and produced the stack illustrated in Figure 4. Figure 4 demonstrates by illustration the comparison between the model having flank 26 and the original image 26' obtained from processing the model-derived synthetic time response, as described above. The breaks in the image are due to poor velocity picks and interference between the reflections from the flat layers (which are now steep events) and the salt. Many commonly used filtering techniques may be performed to reduce the interference between the flat reflectors and the salt. Three-component recording in the borehole is preferred to allow the data processor to enhance reflections coming from the side of the borehole and to attenuate reflections traveling sub-parallel to the borehole. This is analogous to the use of geophone array for reducing ground roll on surface seismic data. It is believed that shear wave mode-conversion of the salt reflection is easier to record (of higher amplitude) than the compressional (primary) salt reflection described above. Thus, the recorded three-component data may be reprocessed using modified P wave to S wave conversion software to repeat the above technique for converted shear waves. The technique could also be applied on shore using one or more transverse shear wave sources. While this new VSP acquisition and processing technique of the present invention has been described in terms of 2-D acquisition and processing, it can be directly extended to provide 3-D coverage. Several source lines or patterns could be acquired at each receiver level using one or more seismic sources. The same processing flow would be followed, except for the substitution of 3-D seismic processing algorithms for 2-D programs. Further, the present invention has been described specifically in a marine environment, however, the method of the present invention may be applied to achieve similar results in land based environments.

Claims: A method of acquiring and processing vertical seismic profile data so as to image a generally vertically extending interface (10) comprising the steps of: generating seismic acoustic pulses by a seismic source (S); placing acoustic pulse receivers (R) in a spaced-apart relation within a wellbore to receive said seismic acoustic pulses; receiving said seismic acoustic pulses that have been reflected from said interface to obtain a total travel time from said seismic source to said acoustic pulse receivers; characterised in that: said seismic source (S) is a surface seismic source, and said wellbore is located between said interface (10) and said seismic source, such that said acoustic pulses to be reflected at said interface and then received by said receivers pass through said wellbore before arriving at said interface; and in that said method further comprises the steps of: determining a first break time when said seismic acoustic pulses generated by said seismic source pass through said wellbore toward said interface; and subtracting said first break time from said total travel time to isolate acoustic travel from the wellbore to the interface (10) and back to pulse receivers (R) in said wellbore, effectively to convert said vertical seismic profile data to pseudo horizontal line data having a two way travel time. The method according to Claim 1 also including the step of: processing said pseudo horizontal line data using multifold processing techniques. The method according to Claim 1 wherein said processing step includes the step of: gathering said pseudo horizontal line data according to common depth points. The method according to Claim 2 wherein said processing step includes the step of: arranging said pseudo horizontal line data according to common midpoints. The method according to Claim 2 wherein said processing step includes the step of: determining an average acoustic velocity; and stacking said data. The method according to any preceding claim wherein said generating step includes the step of: locating said seismic source (S) to provide a near offset relationship. The method according to any of Claims 1 to 6 wherein said generating step includes the step of: locating said seismic source (S) to provide a far offset relationship. The method according to any preceding claim also including the steps of: moving said acoustic pulse receivers (R) to a second location in said wellbore; and generating seismic acoustic pulses a second time. The method according to any preceding claim, wherein said interface comprises the flank of a salt dome. The method according to Claim 9 wherein said step of generating seismic pulses comprises: generating periodic acoustic pulses at a plurality of locations from a moving surface seismic source.

Inventors: ADAMS OLAN T, COX VERNON D, MCCLELLAN BRUCE D, ADAMS, OLAN T., COX, VERNON D., MCCLELLAN, BRUCE D.
Applicants: CONOCO INC, CONOCO INC.
Application year: 1990
Main classification: G01V1
IPC codes: G01V1