CA1207074A - Multiple-point surveying techniques - Google Patents

Abstract

ABSTRACT OF THE DISCLOSURE

METHOD FOR THE INTERPRETATION
OF MULTIPLE-POINT SURVEYING TECHNIQUES

In accordance with the present invention, progressive changes in amplitude as a function of offset of common gathers can be more easily identified by emphasizing the degree of amplitude variation between "near" and "far" amplitude vs. time traces of each gather along a seismic line, and displaying the resulting near and far offset sections side-by-side.
A significant -- and progressive -- change in P-wave reflection coefficient as a function of the angle of incidence (within sections) indicates valuable characteristics, say the fluid hydrocarbon-bearing potential and/or the lithology of the reflecting horizon.

Description

IMPROVED METHOD ~OR THE INTERPRETATION OF
SEISMIC RECORDS TO YIELD VALUABLE CHARACT~RISTICS, SUCH AS GAS-BEARING POTENTIAL AND LITHOLOGY OF STRATA

FIELD OF T~IE INVE~TION
The present invention pertains to the art of seismic prospecting for petroleum reservoirs by multiple-point surveying techniques, and mor~ particularly to the art of converting high-intensity reflection amplitude anomalies associated with one or more common centerpoints observed on seismic record traces into diagnostic indica-tors, say of both hydrocarbon-bearing potential and lithology of the underlying subsurface strata.
BACKGROUND OF THE INVENTION
Seismic prospecting for petroleum involves the creation of acoustic disturbances above, upon, or just below the surface of the earth, using explosives, air guns, or large mechanical vibrators. Resulting acoustic waves propagate downwardly in the earthp and partially reflect back toward the surface when acoustic impedance changes wi~hin the earth are encountered. A change from one rock type to another, for example, may be accompanied by an acoustic impedance change, so that the reflectivity of a particular layer depends on the ~elocity and density content between that layer and the layer which overlies In early years, signal traces of the reflected acoustic waves were recorded immediately in the field as ~isible, side-by-side, dark, wiggly lines on white paper ("seismograms"). At present, the initial reproductions --in a digital format -- are on magnetic tape, and finally are reduced to visible side-by-side traces on paper or film in large central computing facilities.
At such centers, sophisticated processing makes possible the distinction of signals from noise in cases that would have see~ned hopeless in the early days of seis-mic prospecting. Until 1965, almos~ all seismic surveys conducted used an automatic gain control which continu-ously adjusted the gain of amplifiers in the field to ~r~

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account for decreasing amounts of energy from late reflec~
tion arrivals. As a result, reflsction coefficients could 05 not be accurately determined. However, with the advent of the expander circuit and binary gain amplifiers, gain of the amplifiers can now be controlled and amplitudes recorded precisely; this makes it possible to conserve not only the special characteristics of the reflections, but also their absolute amplitudes.
Today, more powerful computers with array pro cessors and economical floating point capabilities also now enable modern geophysicists to maintain control of the amplitude of all recorded signals. The "floating point"
capability is especially effective in expanding computer work size by a large factor and in eliminating the need for computer automatic gain control. As a result of the above advancesr reflections from many thousands of feet below the earth's surface can now be confidently detected 2U and followed through sometimes hundreds of side-by-side traces, the shortening or lengthening of their correspond-ing times of arrival being indicative of the shallowing or deepening of actual sedimentary ~strata of interest.
Apropos of the above has been use of ultra-high amplitude anomalies in seismic traces to infer the pre-sence of natural gas in situ. Seismic interpreters have used so-called "bright-spot" analysis to indicate several large gas reservoirs in the world, especially in the Gulf Coast of the United States. Such analysis is now rather common in the oil industry, but it is not without it.s critics. Not only cannot the persistence of such increased amplitude anomalies be taken as confirmation of the lateral extent of the gas reservoir, but also ~he anomaly itself (in some cases) may not represent reflec-tions of a discontinuity of a gas-bearing medium and its over- or underlying associated rock strata.
However, the problem as to the degree an inter-preter can rely on high-intensity anomalies, in these regards has recently been brought to manageable propor-tions. In the above-identified copending applications, it ~Z~7~7~

is taught that gas-bearing potential and the lithology of one host and cap rock strata can be accurately determined 05 by: (1) obtaining ~ield data in which the data of common centerpoints are associated with more than one source-detector pair, ~2) indexing the data whereby all recorded traces are indicated as being a product of respective source-detector pairs of known horizontal offset and cen-terpoint location, (3) thereafter, associating high-inten-sity amplitude anomalies in the traces in a manner that allows determination of both gas-bearing potential area the lithology of the host and cap strata to a surprisingly accurate degree.
The present invention further improves the ability of the seismologist to correctly identify the lithology and presence of hydrocarbonaceous fluids using certain occurrences in amplitude with offset of such high-intensity anomalies of the seismic records to differen-tiate the former from similarly patterned reflections of other types of configurations containing no accumulationsO
SUMMARY OF THE I~VENTION
In accordance with the present invention, pro-gressive changes in amplitude as a function of offset of common gathers can be more easily identified by emphasiz-ing the degree of amplitude variation between near offset and far offset traces (relative to a common sourcepoint) of each gather along a seismic line, and displaying resulting near and far offset sections. ~esult: the interpreter can easily follow progressive amplitude change in a manner that allows determination, say of both ~luid hydrocarbon-bearing potential, and the lithology of the host and cap rock strata to a surprisingly accurate degree.
In accordance with the present invention, sys-tematic generation of near and far offset traces and sec-tions, is provided in a surprisingly efficient manner using pattern recognition methods that (although conven-tional in the data communications field) have not been used in the context here employed.

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Assume, for example, that a Tlth time sample exits for a gather of traces and the near and far offset traces for such time sample, are to be determined. In order to carry out such a process, first, the traces amplitudes associated with the Tlth time sample are gener-ated, i.e~, the ~ l's for the sample Tl. ~ext, there is a fit of the formulated AT 's to a series of linear and quadratic functions of the for~: (i) A(x) = CO Cl x;
(ii) A(x) ~ CO ~ C2 x2; and (iii) A(x) = CO + Clx + C2x2.
1~ Object: to obtain a least squares best fit of the gener-ated ATl amplitudes to either equation (i), (ii), or (iii), supra. Then amplitudes at preselected near and far values are calculated. That is to say, the best fitting above-identified linear and quadratic equation is solved for a preselected near and far offset value. The process then can be repeated, and then re-repeated for sample times T2..... Tj, to generate a series of pairs o~ near and far traces projected to preselected near and far loca tions offset from the source point locations associated with ths original gather of traces.
Preferably, the near and far traces are grouped together to form a series of sections, best displayed on a side-by-side basis. Result: the interpreter can easily follow change in amplitude as a function of offset from section to section along the entire seismic survey line.
Various aspects of the invention ~re as follows:
A method for determining valuable characteristics of strata in the earth using high-intensity amplitude events in seismic records, comprising the steps of:
(a) generating seismic data, including a record of signals from acou~tic discontinuities associated with said strata of interest by positioning and employing an array of sources and detectors such that centerpoints between selected pairs of sources and detectors form a series of centerpoints along a line of survey, said recorded signals being the output of said detectors;
(b) by means of automated processing means, static-ally and dynamically correcting said recorded signals to 37~
-4a-form corrected traces whereby each of said corrected traces is associated with a centerpoint horizontally mid-way between a source-detector pair from which said each corrected trace was originally derived;
(c) by ~eans of automated processing means, indexing said corrected ~races so that each of said correc~ed traces is identified in its relationship to neighboring traces on the basis of progressive changes in common cen-terpoint location;
(d) deter~ining among a series of analytic functions of known mathema~ical character, a best fit to a~plitude vs. horizontal offset variations of a gather of said corrected traces, said gather of traces being identified with a common centerpoint location and a set of progres-sively changing horizontal offset values;
(e~ predicting near and far amplitude vs. time trace projections for said gather of corrected traces at new offset locations based on said best fitting analytic func-tion, said predicted near and far offset trace projections being identified with offset locations ~alling on opposite sides of said set of changing horizontal offset values;
(f) displaying a first series of said trace projec-tions of step (e) associated with near offset locations, .
side-by~side with a second series of trace projections also of step (e) assoc~ated with far offset locations, said first and second series of displayed traces all being associated with at least the same general common groups of centerpo;nts so that progressive change in a high-inten-sity amplitude event in said displayed traces is identi-fied as a function of progressive change in centerpointvalues.
A method for converting an original multitrace seismic record into an improved section having increased capability as to fluid hydrocarbon-bearing potential and/or lithologic nature of high-intensity amplitude events related to reflections from subsurface strata, said improved section being composed of a plurality of ampli-tude-versus-centerpoint-and-time traces, said original record consisting of a plurality of multitrace seismic ":

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-4b-traces of amplitude-versus-horizontal ~oordinate-and-time, each of said traces constituting energy derived in asso-ciation ~ith a particular source-detector pair of known horizontal offset and of known centerpoint location, and representing, in part, event ref~ections from said subsur-face strata, said conversion comprising the s~eps of:
(a) classifying said original tr~ces on the basis of common but progressively changing horizontal offset values and common but progressively changing common centerpoint locations, whereby each resulting trace is identified by a centerpoint location common to at lea~ another trace and a known horizontal offset value;
(b) determining among a series of analytic functions of known mathematical character, a best fit to amplitude vs. offse~.variations of said each resulting trace and said at least another trace;
(c) predicting near and far amplitude vs. offset trace projections for said resulting trace and another trace at new offset locations based on ~aid best fitting analytic function, said predicted near and far offset trace projections baing identified with offset locations falling on opposite sides of said set of changing horizon-tal offset values;
(dj displaying a first series of said trace projec-tions of step (c) associated with near offset locations,side-by-side with a second series of trace projections also of step ~c) ~ssociated with far of~set locations, to form at least a segment of said improved section; said first and second series of displayed traces all being associated with at least the same general common group of centerpoints so that progressive change in a high-inten-sity amplitude event in said displayed traces is identi-fied as a function of progressive change in centerpoint values.
3~ A method for determining hydrocarbon-bearing potential and/or lithology of strata in the earth using high-intensity amplitude events in seismic records, com-prising the steps of:
(a) generating seismic data, including a record of signals from acoustic discontinuities associated with said ., ~

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-4c-strata of interest by positioning and employing an array of sources and detectors such that centerpoints between selected pairs of sources and detectors form a series of centerpoints along a line of survey, said recGrded signals being the output of said detectors;
(b) by means of automated processing means, static-ally and dynamically correcting said recorded signals to form corrected traces whereby each of said corrected tra-ces is associated with a centerpoint horizontally mid~ay between a source-detector pair from which said each corrected trace was originally derived;
(c) by means of automated processing means, indexing said corrected traces so that each of said corrected tra-ces is identified in its relationship to neighboring tra-ces on the basis of progressive changes in common center-point location;
(d) determining from among a series of analytic func-tions of known mathematical character, a best fit to amplitude vs. horizontal offset variations of a gather of said corrected traces, said gather of traces being identi-fied with a common centerpoint location and a set of pro-gressively changing horizontal offset values;
(e) predicting near and far amplitude vs. time trace projections for said gather of corrected traces at new offset locations based on said best fitting analytic func-tion, said predicted near and far offset trace projections being identified with offset locations falling on opposite sides of said set of changing horizontal offset values;
(f) generating a first envelope of said trace ampli-tude projections of step (e) associated ~ith near offset locations and a second amplitude envelope of said trace projections of step (e) associated with far offset loca-tions and subtracting the two envelopes one from the other to form a difference envelope;
(9) displaying said difference envelopP of step (f) so as to depict amplitude vs. time change as a function of centerpoint coordinate so that progressive change in a high-intensity amplitude event in said displayed traces is identified as a function of progressive change in center-point values.

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7'f1'7g -4d-A method for converting an original multitrace seismic record into an improved section having increased capability as to hydrocarbon-bearing potential and/or lithologic nature of high-intensity amplitude events related to reflections from subsurface s~rata containing the hydrocarbons, said improved section being composed of a plurality of amplitude-versus-centerpoint-and-time traces, said original record consisting of a plurality of multitrace-seismic traces of amplitude-versus-horizontal coordinate~and-time, each of said traces constituting energy derived in association with a particular source-detector pair of known horizontal offset and of known centerpoint location, and representing, in part, event reflections from said subsurface strata, said conversion comprising the steps of:
(a) classifying said original traces on the basis of common but progressively changing horizontal offset values and common but progressively changing common centerpoint locations, whereby each resulting trace is identified by a centerpoint location common to at least another trace and a known horizontal offset value;
(b) determining with regard to a series of analytic functions of known mathematical character, that one of said series is the best fit to amplitude vs. time varia-tions of said each resulting and said at least anothertrace;
(c) predicting near and far amplitude vs. time trace projections for said resulting and ano~her traces at new offset locations based on said one, best fitting analytic function, said predicted near and far offset trace projec-tions being identified with offset locations falling on opposite sides of said set of changing horizontal offset values;
(d) generating a first series of trace amplitude projections vs. time of step (c) associated with near offset locations, and a second series of trace amplitude projections vs. time associated with far offset locations and subtracting increments of said first and second series normalized to the same time sample, one from the other to ~Z~7~7 -~e-form at least a segment of said improved section;
(e) displaying said improved section depicting ampli-tude change as a function of time and centerpoint coor-dinate so that progressive change in a high intensity amplitude event in said displayed traces is identified as a function of progressive change in centerpoint values.
A method for datermining valuable characteristics of strata in the earth using high-intensity amplitude events in seismic records, comprising the steps of:
(a) generating seismic data, including a record of signals from acoustic discontinuitie5 associated with said strata of interest by positioning and employing an array of sources and detectors such ~hat centerpoints between selected pairs of sources and detectors form a series of centerpoints along a line of survey, said recorded signals being the output of said detector5;
(b) by means of automated processing means, static-ally and dynamically correcting said recorded signals to form corrected traces whereby each of said corrected traces is associated with a centerpoint horizontally mid-way between a source-detector pair from which said each corrected trace was originally derived;
(c) by means of automated processing means, indexing said corrected traces in two dimensions whereby each of said corrected traces is identified in its relationship to neighboring traces on the basis of progressive changes in horizontal oE~set value versus progressive changes in common centerpoint location;
(d) weighting said series of traces of step (c) by semblance coefficients wherein after a series of normalized ratios of output-to-input energy is generated by stacking, events in the traces associated with a limited number of phases are better indicated;
(e) displaying said weighted traces or representations of said weighted traces of (d), whereby progressive change in a high-intensity amplitude event of said displayed traces or representations of said traces is identified as a func-tion of progressive change in said horizontal offset values.

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Further features of the invention will become more apparent upon consideration of the following detailed description of the invention when taken in connection with the accompanying drawings, wherein:
FIGS. 1, 2 and 3 are geometrical plan and trans-formed views of a grid of centerpoints produced from (i) an array of seismic sources and detectors and (ii) seismic processing whereby a series of locational traces associa~
ted with individual centerpoints between respective source-detector pairs can be associated together in a meaningful way;

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FIG. 4 is a model of typical reflecting horizons wlthin an earth formation that can be associated with the characteristics of the locational traces of FIGS~ 1 and 3;
FIGS. 5 and 6 (first sheet of drawings) are plots of reflection coefficient as a function of angle of incidence of seismic waves associated with the reflectillg horizons o-f FIG. 4;
FIGS. 7 and B are flow diagrams of processes akin to those shown in FIGS. 2 and 3 for carrying out the method of the present invention, using a programmed digi-tal computing system;
FIGS. 9A and 9B are schematic diagrams illus-trating certain steps of the flow diagrams of FIGS. 7 and 8 in more detail;
FIG. 10 is a schematic diagram of elements with-in a typical digital computing system; and ~IGS. 11-16 are true record sections and por-tions of sections, illustrating the diagnostic capability of the method of the present invention.
PREFERRED E~BODIMENTS OF THE INVENTIO~
Before discussion of an embodiment of the inven-tion within an actual field environment, it may be of interest to indicate lithology limitations associated with the present invention. For example, anomalies associated with gas sands over shale cap rock are one example in which the method of the present invention offers surpris-ing results; another relates to gas-saturated limestone over shale. Also of importance is the relationship between Poissonls ratio and resulting high-intensity amplitude anomalies provided on seismic traces.
While Poisson's ratio (o) has the general formula 35a = Vs 2 (A)

2. P
Vs where Vp is compressional velocity and Vs is shear velo-city of the medium, this concept is not without physical , -~LZ~7~7~

significance. For example, considering a slender cylin-drical rod of an elastic material and applying a compres-o5 sional force to the ends, as the rod changes shape ~thelength of the rod decreasing by ~L, while the radius increasing by ~R), Poisson's ratio is defined as the ratio of the relative change in radius (~R/R) to the relative change in length (~L/L). Hence compressible materials have low Poisson's ratios, while incompressible materials (as a liquid) have high Poisson's ratios.
Equation (A) above indicates the relationship of the compressional and shear wave velocities of the mate-rial, Vp and Vs respectively; i.e., that Poisson's ratio may be determined dynamically by measuring the P-wave and S~wave velocities. Only two of the three variables are independent, however.
~ecent studies on reflection and transmission seismic waves use~ul in geophysical applications include:
(1) Koefoed, O., 1955, for "On the Effect of Poisson's Ratios of Rock Strata in the Reflection Coefficients of Plane Waves", Geophysical Prospecting, VolO 3, No. 4.
(2) Koefoed, O., 1962, for "Reflection and Transmission Coefficients for Plane Longitudinal Incident Waves", Geophysical Prospecting, Vol. 10, No. 3.

(3) Muskat, M. and Meres, M.W., 1940, for "Reflection and Transmission Coefficients for Plane Waves in Elastic Media", Geophysics, Vol. 5, No. 2.
~4) Tooley, R.D., Spencer, T.W. and Sagoci H.F., for "Reflection and Transmission of Plane Compressional Waves", Geophysicst Vol. 30, No. 4 (1965).
(5) Costain, J.K., Cook, K.L. and Algermisshi ! S.T., for !'Amplitude, Energy and Phase Angles of Plane SP Waves and Their Application to Earth Crustal Studies", ~ull.
Seis. Soc. Am., Vol. 53, p. 1639 et seq.
All of the above have focused on the complex modeling of variation in reflection and transmission coefficients as a function of angle of incidence.

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The problem is complicated, however. ~.g., isotropic Media with layer index of the strata, i=l for 05 the incident medium and i=2 for the underlying medium, have been modeled using equations for P-wave reflection coeficient Apr an-] for P-wave transmission displacement amplitude coefficient Apt~ For each of the media, i.e., the incident or underlying medium, three independent vari-ables exist: P-wave velocity, a and bulk density, or a total of six variables for both media.
But to provide for the many combinations of possible variations, the above-listed studies have either:
(a) generated many (literally thousands) plots of a mathematical nature for various parameters, values in which there was little relationship with true geophysical applications, since the latter were hopelessly obscured and unappreciated; or (b) made simplistic assumptions that, although using actual calculations, nevertheless did not express the true nature of transmission and reflection coefficients, in particular lithological situations associated with the accumulation of gaseous hydrocarbons within an actual earth formation.
While reference (2) concludes that change in Poisson's ratio in the two bounding media can cause change in the reflection coeficient as a function of angle of incidence, reference (2) does not relate that occurrence to lithology associated with the accumulation of gaseous hydrocarbons in the surprising manner of the present invention.
In th!e above-identified patent applications, it is taught that gas-containing strata have low Poisson's ratios and that the contrast with the overburden rock as a function of horizontal offset produces a surprising result: such contrast provides for a significant -- and progressive -- change in P-wave reflect:ion coefficient at the interface of interest as a function of angle of inci-dence of the incident wave. Thus, determining both the gas-bearing potential and the lithology of host media is 7~

simplified by relating progressive change in amplitude intensity as a function of offset between source-detector 05 pairs, i.e., angle of incidence being directly related to offset. However, there is still a need in some cases to further emphasize the degree of amplitude change as a function of offset especially with respective source-detector pairs associated with near and far offset loca-tions of a gather of traces.
By the terms "near" and "far" offset locations,it is meant that such are measured with respect to the source locations associated with the original source points where the seismic waves were generated. ~ence, they represent the degree of horizontal offset distance that exists between such field locations, the source and receiver as the data was collected in the field.
Now in more detail, attention should be directed to the Figures, particularly FIG. l. ~ote that, inter 2~ alia, FIG. l illustrates in some detail how the terms of interest in this application are derived: e.g., the term "centerpoint" is a geographical location located midway between a series of sources Sl,S2...Sn of a geophysical field system 9 and a set of detectors Dl,D2...Dm at a datum horizon near the earthts surface. The centerpoints are designated Cl,C2...Cp in the Figure, and are asso-ciated with a trace derived by placement of a source at that centerpoint location followed immediately by relocat~
ing a detector thereat.
I.e., if the sources Sl~.. Sn are excited in sequence at the source locations indicated, traces received at the different detector locations shown can be related to common centerpoints therebetween, and a gather or group of traces is formed. I.e 9 if the reflecting interface is a flat horizon, the depth point where a reflection occurs will define a vertical line which passes through the centerpoint of interest. Applying static and dynamic corrections to the field traces is equivalent (under the above facts) to placing the individual sources Sl,S2...Sn at the centerpoint in sequence followed by ~2~7~7~

01 _9_ replacement with the detectors Dl...Dm of interest at the same locations. If the traces associated with a common ~5 centerpoint are summed, a series of enhanced traces, sometimes called CDPS ~Common Depth Point Stack) traces, is provided. But before such traces are summed, such display cap be enhanced to surprisingly indicate the presence of fluid hydrocarbons in a host strata as well as the lithology of the latter.
FIG. 2 illustrates reflection phenomena of a three-layer model typical of a young, shallow geologic section 10, such as found in the Gulf Coast, illustrating how reflection phenomena associted with the traces asso-ciated with the field system 9 of FIG. 1 can be related to the presence of gas.
Section 10 includes a gas sand 11 embedded in a shale stratum 12. Assume a Poisson's ratio of 0.1 for the gas sand and of 0.4 for the shale, a 20% velocity reduc-tion at interface 13, say from 10,0007/sec to 8000'/sec, and a 10% density reduction from 2.40 g/cc to 2.16 g/cc.
The actual P-wave reflection coefficient ~pr can be related to section 10 by Equation (1) below; also, P-wave transmission displacement amplitude coef~icient Apt can similarly be related in accordance with Equation (2) below.

Apr ~E T X ( 1) f+T+X
Apt = h2 2alkl2 (Clv + C2~ (2) hl(f + T + X) f = kl2k2~(alC2 + a2Cl) T = b2n2 + alclv2 (4) X = a2C2 (~2 + 4alC1~2b2 n = ~2-~1 (6) 7~

o 1 --1 o-~ 1 (7) v = ~E2 + 2b2 (8) l~ = El + 2~b2 (9) ~i = k2i ~ 2b~ (10) ~ ~2/~1 (11) ~i = PiVsi (12) b = hlsin~ (13) a2i = h2i ~ b2 (14) c2 = ~2 _ b2 (15) hi = l/Vpi ~16) ki = l/Vsi (17) Vpi p-wave velocity Vsi s-wave velocity Pi density i layer index 9 angle of incidence Equations (1) and (2) are, of course, the two basic equations of wave travel in an earth formation and are for isotropic media with the layer index being i=l for the incident medium and i=2 for the underlying medium.
Equations (3) through (17) simply define intermediate variables.
As an example of calculations associated there-with, if ~=0 (normal incidence), the P-wave reflection coefficient Apr is equal to about -0.16 and +0.16, respec-tively.
FIG. 3 illustrates change in reflection coeffi-cient as a function of angle of incidence ~ for the three-layer model of FIG. 2.
Note that solid lines 20, 21 illustrate the effects of reflection (and transmission, by omission) on the top and base of the gas sand. In line 20, at ~-0, ~2~7~7~

note that the Apr equals -0.16; while at ~=40, the Apr is about -0.28. That is, rather a surprisingly large change 05 in the reflection coefficient as a function of angle of incidence occurs, with the greatest change occurring between ~=20 and ~=40.
For the bottom layerl line 21 changes at about the same rate, but in opposite sign~ I.e., at ~=, Apr is about +0.16 and at 9=40, Apr is about +0.26. Again, the greatest change in Apr occurs between ~=20 and ~=40.
As a result, the amplitude of the seismic wave reflected from this model would increase about 70% over the angle of incidence range shown, i.e., over the incremental 40 lS degrees shown.
While angles of incidence equal to 4no may seem a little large for reflection profiling (heretofore, most data arriving beyond 30 being thought useless and muted out), experience has now nevertheless shown that reflec-tion data can and do arrive at reflection angles greater than 30. Hence, the angles of incidence must be deter-mined, and the straight-ray approach to estimate such angles of incidence (using depth-to-reflector and shot-to-detector and-shot-to-group offset), is useful.
FIG. ~ illustrates another plot associated with a three~layer model akin to that shown in FIG. 4, but in which the sandstone contains gas but is buried deep below the earthls surface. The values for the three-layer model of FIG. 2 are again used except that the velocity change from shale to sand is only 10%, or from 10,000'/sec to 9000l/sec. As shown, curves 25, 26 are even more sig-nificant: both curves are seen to increase in magnitude from over the 40 of change in the angle of incidence.
However, field results have not verified these results, prior to the inventions described in the above applica-tions, since Poisson's ratio in such gas sands may be strongly affected by depth.
FIG. 5 is a diagram which illustrates a data "addressing" technique as practiced by the present inven-tion; in the Figure, the traces are generated using an ~Z~ 79~

Dl end-shooting array of 48 detectors with source and detec-tors advancing one detector interval per shot point.
05 Result: a ~4-fold CDP-stacked record section. Note further: each centerpoint is associated with 24 separate traces of varying offset.
To further understand the nature of FIG. 5, assume that the sources ~l,S2...Sn are sequentially located at shotpoints SPl,SP2...SPn at the top of the Figure. Assume also that the detectors are placed in line with the sources, i.e., along the same line of survey A at the detector locations Dl,D2...Dm. After each source is activated, reflections are received at the detectors, at the locations shown. Then by the "rollalong" technique, the source and detector spreads can be moved in the direc-tion B of survey line ~ and the process repeated to pro-vide a series of traces. The latter are associated with centerpoints midway between the respective detector-source pairs. In the Figure, assume source Sl has been located at shotpoint SPl and excited. Midway between SPl and each of the detectors, at Dl,D2...Dm is a series of center-points Cl,C2...Cn. The latter are each associted with a trace. In this regard and for a further description of such techniques, see U.S. Patent 37597,727 for "Method of Attenuating Multiple Seismic Signals in the Deterrnination of Inline and Cross-Dips Employing Cross-Steered Seismic Data", Judson et al, issued August 3, 1971, and assigned to the assignee of the present application. With appro-priate static and dynamic corrections, the data can be related to the common centerpoints midway between indi-vidual source points and detectors, as discussed in the above-noted reference.
But by such a field technique, data provided generate 24 separate traces associated with the same cen-terpoint Cl...Cn. To correctly index ~"address") these traces as a function of several factors including horizon-tal offset and centerpoint location, involves the use of stacking chart 44.
FIG. 6 illustrates stacking chart 44 in detail.

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As shown, Chart 44 is a diagram in which the traces are associated with eitner a plurality of oblique 05 common profile lines PLl,PL2..., or a series of common offset and centerpoint locations at 90 degrees to each other. For best illustration, focus on a single shot-point, say SPl, and on a single detector spread having detectors Dl,D2...Dm of FIG. 6 along survey line A.
Assume a source is located at shotpoint SPl and activated thereafter. The detector spread and souce are "rolled"
forward along survey line A in the direction B, being advanced one station per activation. Then after detection has occurred, and if the resulting centerpoint pattern is rotated 45 about angle 46 to profile line PLl and pro-jected below the spread as in FIG. 6 as a function of common offset values and centerpoint positions, the chart 44 of FIG. 6 results. Of course, each centerpoint has an amplitude vs. time trace associated therewith, and for didactic purposes that trace can be said to project along a line normal to the plane of the Figure.
It should be emphasized that the centerpoints provided in FIGS. 5 and 6 are geographically located along the line of survey A in line with the source points SPl,SP2... As the locational traces are generated, the chart 44 aids in keeping a "tag" on each resulting trace.
As the detector spread and sources are rolled forward one station and the technique repeated, another series of traces is generated associated with centerpoints on new profile line PL2. That is, although the centerpoints are geographically still associated within positions along the survey line A of FIG. 5, by rotation along the angle 46, the new centerpoint pattern Cl',C2'...Cn' can be horizon-tally and verticall~ aligned with centerpoints previously generated. I.e., at common offset values tin horizontal alignment) certain centerpoints are aligned, viz, center-point Cl aligns with Cl' as shown; further C2 is aligned with C2', etc. Also, there are traces that have common centerpoints. I~e., at common centerpoints (in vertical alignment) centerpoint C2 aligns with centerpoint Cl', and 7~

~1 centerpoints C3,C2' and Cl" are similarly aligned. Thus, via chart 44, each trace associated with a centerpoint can 05 be easily "addressed" as to:
(i) its actual geographical location ~i.e., along phantom lines normal to diagonal profile lines PLl,PL2...
along common location lines LLl,~L2.~.), so that its actual field location is likewise easily known;
(ii) its association with other traces along common horizontal offset lines COLl,COL2...COLX; and (iii) its association with still other traces along common vsrtical centerpoint location lines CPLl,CPL2...
Also, "addressing" the traces allows such traces to be easily enhanced as by using amplitude projection (of the trace gather) to new "near" and "far" offset loca-tions, as in the manner of FIGS. 7 and 8. Briefly, as shown in FIGS. 7 and 8, by using only the amplitudes variation between the near and ~ar offsets, the inter-preter can more readily determine valuable characteris-tics, such as the fluid hydrocarbon-bearing potential and lithology of the host media, while simplifying the number of parameters required to render a viable display of such data.
Now, in more detail, FIGS. 7 and 8 are flow diagrams illustrative of a computer-dominated process in which the functions required by the method o the present invention can be easily ascertained. Preliminary to the steps shown in FIG. 7, assume that a section of seismic data has been analyzed for "bright spots"; such events are known by geographical location and/or a time/depth basis7 and the traces have been dynamically and statically corrected, as hereinbefore described.
The steps of FIG. 7 include generating addresses for the data that include a common offset address in the manner of FIG. 2, common centerpoint address and an actual geographical location address also in the manner of FIG. 2. Next, near and far traces (and ultimately sec-tions thereof) are generated based on an analytic rela-tionship that first best approximates the actual variation ~Z~7~?7~

Ol -15-in amplitude versus offset within each gather of traces for a series of time samples and then determines the pro-05 jected amplitudes of the near and far traces based on thefunctional form of the best fitting curve. Finally, the generated near and far sections are displayed side-by-side whereby the character of the amplitude event of interest is indicated as a function of changing centerpoint values.
If the event character abruptly changes from the near to far sections (normalized to common centerpoint values) then there is a high likelihood that the event is indica-tive of strata containing hydrocarbons. Also the lithology of the host strata is easily determined based on the assumption and operations described in detail in the above-identified applications as well as in less detail below.
In more detail, after the addresses have been generated, amplitudes of side-by-side traces of each ~0 gather can be re-indexed as a function of time and offset.
That is to say, for a time sample, say time sample Tl, of the trace gather Gl, all amplitudes for that sample are first re-indexed as a function of offset (if not already so ordered, see FIG 9A). Next, the generateA amplitude vs. offset data are compared to a series of analytic func-tions and the "best fit" determined based on a least -square analysis. That is to say, the linear or quadratic equation that best fits the data is the one in which the sum of the squares of the distances (associated with the 3n amplitudes of the trace gather) is minimum, In order to simplify the step of best fit~ing the form of the actual data to a specified linear or qua-dratic equation, usually three mathematical functions are specified: a linear equation of the form A (x~ = CO + Clx;
and quadratic equations of the form A (x) = CO ~ C2x2 and A (x) = CO + Clx = C2x where A (x) is the variation in amplitude of the data as a unction of offset and CO, Cl and C2 are constants determined by standard pseudo inverse matrix methods conventionally available in the seismic processing industry. After a best fit of the data 7~L

associated with the time sample Tl has been obtained, the near and far offset amplitude values are next generated 05 based on the functional form of the best fitting equation, see FIG. 9B. The data is then stored~ Then after the near and far offset amplitudes associated with the remain-ing time samples T2..... Tj of the gather Gl have been generated, the process is repeated for neighboring gathers 10 G2....Gi.
For generating near and far offset traces (andultimately sections thereof), new offset values to which the field data is projected (which of course are outside of the set of offsets associated with the traces of each original gather) must be chosen, In the case of the near offset location, the choice is a conventional one--zero (FIG. 9B). That is to say, for the linear or quadratic equations set forth above x is set equal to zero and the amplitude solutions as a function of different time sam-ples Tl...Tj, determined. ~hile in the process of gener-ating near trace data, the choice can be said to be somewhat obvious [i.e., setting X to zero in either equa-tion (i), (ii), or (iii)], not so in the case of far off-set trace and section determination.
For generating such far offset traces and sec-tions, the offset values chosen must not only be constant and outside the set of usual offset values of the common gather (as in near trace processing), but also they must be values customarily acceptable to those skilled in the art. In this regard, mute offsets as used in conventional seismic processing, have been found to be adequate. Also offset locations associated with common emergence angles of adequate frequent content, are likewise useful. In that way, the offset values chosen for far projection purposes are those values either (i) that are convention-ally associated with the process of excluding from the early parts of the offset traces signals dominated by refraction energy, or (ii) that are associated with emer-gence angles such that a long offset traces associated ~0 7~

therewith has a frequency content that is not appreciably lower than those of neighboring traces.
S However, the space coordinates of the final traces is not an offset coordinate but in fact is a cen-terpoint location that is common to the common ~ather from which the near and far traces were produced. Hence the resulting plots easily correlate with actual field addresses.
In carrying out the above processes on a high-speed basis, a fully programmed digital computer can be useful, and moreover is the best mode for carrying out the present invention. But electromechanical systems well known in the art can also be used. In either case, the field traces must first undergo static and dynamic correc-tion before the traces can be displayed as a function of offset to determine their potential as a gas reservoir.
Such correction techniques are well known in the art --2U see, e.g.~ U.S. Patent 2,838,743, of O.A. Fredriksson et al, for "Normal Moveout Correction with Common Drive for Recording Medium and Recorder and/or Reproducing Means", assigned to the assignee of the present application, in which a mechanical device and method are depicted. Modern processing today uses properly programmed digital compu-ters for that task in which the data words are indexed asa function of, inter alia, amplitude, time, datum height, geographical location, group offset, velocity, and are manipulated to correct for the angular and horizontal offset; in this latter environment, see U~S. 3,731,269, Judson et al, issued May 1, 1973, for "Static Corrections for Seismic Traces by Cross-Correlation Method", a compu-ter-implemented program of the above type also assigned to the assignee of the present invention. ~lectromechanical sorting and stacking equipment is also well known in the art and is of the oldest ways of canceling noise. See, for example, the following patents assigned to the assig-nee of the present invention which contain sorting and stacking techniques, including beam s~eering techniques:
~0 ~'7~7~

Ol -18-Patent Issued Inventor Title 3"597,727 12/30/68 Judson et al Method of Attenuating 05 Multiple Seismic Signals in the Determination of Inline and Cross-Dips Employing Cross-Steered .5eismic Data 3,806,863 4/23/74 Tilley et al Method of Collecting Seismic Data of Strata Underlying ~odies of Water 3,638,178 1/25/72 Stephenson Method for Proces.sing Three-Dimensinal Seismic Data to Select and Plot Said Data on a Two-Dimen-sional Display Surface 3,346,840 10/10/67 Lara Double Sonogramming for Seismic Record Improve-ment 3,766,519 10/16/73 Stephenson Method for Processing 2~ Surface Detected Seismic Data to Plotted Reprs-sentations of Subsurface Directional Seismic Data 3,784,967 1/8/74 ~,raul Seismic Record Processing Method 25 3,149,302 9/15/74 Klein et al Information Selection Programmer Emp~oying ~elative ~mplitude, Abso-lute Amplitude and Time Coherence 3,149,303 9/15/64 Klein et al Seismic Cross-Section P].otter FIG. ln illustrates particular elements of a computing system for carrying out the steps of FIGS. 7, 8, 9A and 9B. While many computing systems are available to carry out the process of the invention, perhaps to best illustrate operations at the lowest cost per instruction, a microcomputing system 50 is didactically best and is presented in detail below. The system 50 of FIG. 10 can be implemented on hardware provided by many different manufacturers, and for this purpose, elements provided by Intel Corporation, Santa Clara, California, may be ~2~ 7~

preferred. Ho~ever, where a central center for seismic data processing i~ available, a large main-frame computing system (such as an IBM~370/65) is usually already in place; and thus for most applications involving the present invention, such a system becomes the best mode for carrying it out.
System 50 can include a CPU 51 controlled by a control unit 52. ~wo memory units 53 and 54 connect to the CPU 51 through BUS 55. Program memory unit 53 stores instructions for directing the activities of the CPU 51 while data memory unit 54 contains data (as data words) related to the seismic data provided by the field acquisi-tion system. Since the seismic traces contain large amounts of bit data, an auxiliary memory unit 55 can be provided. The CPU 51 can rapidly access data stored through addressing the particular input port, say at 56 in the Figure. Additional input ports can also be provided to receive additional information as required from usual external equipment well known in the art, e.g., floppy disks, paper-tape readers, etc., including such equipment interfaced through input interface port 57 tied to a key-board unit 58 for such devices. Using clock inputs, con-trol circuitry 52 maintains the proper sequence of events required for any processing task. After an instruction is fetched and decoded, the control circuitry issues the appropriate signals (to units both internal and external) for initiating the proper processing action as set forth above.
In addition to providing both mathematical pro-jections of the trace data of each original gather and displays of such projections on a side-by-side basis~ the system 50 can also allow for the testing of the contents of the projections against certain known trends in the original data to better pinpoint the, say fluid hydrocar-bon-hearing potential and/or lithology of the surveyed earth formation. Such decisions relate to certain rela-tionships inherently involved in the data.

7~7~

Note that prior related patent applications, op.
cit~ teach that zones of gaseous hydrocarbon accunulation 05 can be accurately identified by determining if first high-intensity events exist in the trace gathers of interest and then next if the events can be associated with the presence of gaseous hydrocarbonst vi~., answering the ques~ion, "Does the amplitude of such events change pro-1~ gressively as a function of horizontal offset?", in theaffirmative. Such a conclusion involves a precursor step in which the events of interest (from one gather with same event in another gather) are contrasted with each other.
And if there appears to be a detectable change in the a~plitude character of the event of interest, say a rever-sal in UP- or DOWN-scale trend, then the conclusion that such change was brought about by the presence of gaseous hydrocarbons has a high probability of being true. And after interrogation via a look-up table, the lithologic character of the underlying strata is also capable of determination.
Such decisions and the results of those deci-sions are automatically controlled by the system S0.
After picking and codifying the amplitudes of the event(s) of interest, i.e., projecting near and far amplitudes via a least-squares fit, the system 50 also can automatically determine their UP- or DOWN scale trend; determine if the trend is a reversal of prior calculted data, anA depending on whether or not a reversal is found (assume that it has been), highlight the reversal; and then cornpare its direc-tion with single-variable lithology table so as to indicate both the gas-bearing potential and the lithology of the strata. With regard to the operation of the latter table, it comprises a LOOK-UP function in which the UP- or DOWN-scale trend of the amplitude direction (with offset) of theindividual 3ather triggers the printing of an appropriate lithologic tag.
For outputting information, the system 50 can include a printer unit 59 by which say, the resul~s of the 7~

0 1 ~

lithology determination steps (of the interrogation of the lithology LOOK-~P table) are printable.
05 Of more use as an output unit, however, is disk unit 60, which can temporarily store the datar ~hereafter, an off-line digital plotter capable of generating a series of displays is use~3 in conjunction with the data on the disk unit 60. Such plotters are available in the art, and one proprietary model that I am familiar with uses a compu-ter~controlled CRT for optically merging onto photographicpaper, as a display mechanism, the seismic data. ~riefly, in such a plotter the data are converted to CRT deflection signals; the resulting beam is drawn on the face of the CRT
and the optically merged record or the event indicated, say via photographic film. After a predetermined number of side-by-side lines have been drawn, the film is processed in a photography laboratory and hard copies returned to the interpreters for their review.

Diagnostic capability provided by the method of the present invention is better illustrated in the Examples set forth belowO
Example I
Seismic data were obtained in the Sacramento Valley, California. These data, in CDP-stacked form are shown in FIG. 11. Three discovery wells (located at about CP-109, CP-98, and CP-85) penetrate a 100-foot sand which is almost fully gas-saturated. The developed portiGn of the field extends from about CP-75 to CP-130. Gas occurs at a depth of about 7,000 feet which corresponds to a time -of about 1.7 seconds on the plots.
The near and far projected trace sections 80, 81 are shown in FIGS. 12 and 13. Note by comparing the sec-tions that the amplitudes over the regions and depths of interest increase with offset within the plots, and more-o~er correlate well ~ith the gas find of interest.
Example II
Seismic data were also obtained from Alaska, and are depicted in CDP-gathered format in FIG. 14. Discovery $Z~7~

wells are located at about CP-140 and CP-110 and penetrate a series of stringers containing gaseous hydrocarbons.
0S The field extends from about CP-105 to CP-150.
Gas occurs at a depth of about 3,500 feet which corresponds to a time of about 0.9 seconds on the plots.
Near and far projected trace sections 84 and 85 are shown in FIGS. 15 and 16. A comparison of the sections 5hows that the amplitudes over the regions and depths of interest increase with offset within the plots, and more-over correlates well with the gas find of interest.
It should thus be understood that the invention is not limited to any specific embodiments set forth here-in, as variations are readily apparent.
For example, envelopes of the amplitudes of eachof the near and far traces can be genzrated using conven-tional averaging processing (say, using the root mean square of many amplitude values associated with the zero and 90 wavelets of the stored data, i.e., using several amplitude samples over several time samples first at zero phase and then shifted in phase 90), followed by the sub~
traction of the generated envelopes (one from the other) as a function of common centerpoint location. The resulting difference envelope is more reliable since any one segment is an average of several amplitude values over many time samples. Hence, noise within the original section tends to be suppressed.
In addition, note that the prior-mentioned pre-diction techniques for determining near and far trace pro-jections, can also utilize matrix equations of the following form.
PSE~DO INVERSE MATRIX EQUATIONS
Assume that these N traces per gather with off-3~ sets Xj and amplitudes Aj available for processing and thatthe analytic functions are of the form described above, viz:
A(j) = CO + Clx (B) A(j) = CO + C2x2 (C) 40 A(j) = CO ~ Clx + C2 x2 (D) ~Z(~7~

For equation (C) least squares soiution in matrix form for constants C0 and C2 is:
05 CO N ~Xi2 -1 ~Ai C2 ~xi2 ~xi4 ~AiXi Letting:
DET = N . ~Xi4 ~ (~Xi2)2 Then the evaluation of the constants C0 and C2 are further siMplified. 2 C = X4 . ~Ai - XET ~AiXi 2 DET Ai DET- . ~AiXi2 As the amplitudes of the near and far traces are projected, such processing involves substitution of a finite offset value, i.e., offset value Xp, in the above equations, as follows:

Projection at offset Xp:

A(Xp) = CO + C2Xp2 ~X4-Xp2 X2 DET

+ Nxp2_~X2 ~AiX 2 = ~WiA

where:
W = ~X4 - Xp2 ~x2 ~ NXp2 - ~x2 2 and:

Wi = Ko + K2 . Xi2 Moreover, since the constants Ko and K2 are easily evaluated, equation (C) can be rapidly solved.

~Z~7~7~

In like manner, equations ~B) and (D~ are also solvable. For equation (B), e. g., application of the oS above matrix form provides for a projection at Xp of the form:

A (Xp) = ~Wj Aj where:
Letting DET = N ~x2 - (~X)2 Wi D~TP ~X + NXp - ~X X

or Wi = Ko ~ Kl Xi Note that in the above form, that if the projected offset location is about equal to 2/3 of the maximum offset value, then Xp = ~X2/~X ~ 2/3 xmaX;
Ko = 0; and Wi = KlXi Likewise for equation (D), application of the above matrix form provides for a projection of Xp of the form A(Xp) = ~WiA
where:
Wi = Ko + ~lXi + K2Xi and K~s = r (~xi, ~:xi2, EXi3, ~xi4, xp, N) Thus, the invention is to be given the broadest possible interpretation within the terms of the following claims.

Claims (26)

THE EMBODIMENTS OF THE INVENTION IN WHICH AN EXCLUSIVE
PROPERTY OR PRIVILEGE IS CLAIMED ARE DEFINED AS FOLLOWS:

1. A method for determining valuable characteristics of strata in the earth using high-intensity amplitude events in seismic records, comprising the steps of:
(a) generating seismic data, including a record of signals from acoustic discontinuities associated with said strata of interest by positioning and employing an array of sources and detectors such that centerpoints between selected pairs of sources and detectors form a series of centerpoints along a line of survey, said recorded signals being the output of said detectors;
(b) by means of automated processing means, static-ally and dynamically correcting said recorded signals to form corrected traces whereby each of said corrected traces is associated with a centerpoint horizontally mid-way between a source-detector pair from which said each corrected trace was originally derived;
(c) by means of automated processing means, indexing said corrected traces so that each of said corrected traces is identified in its relationship to neighboring traces on the basis of progressive changes in common cen-terpoint location;
(d) determining among a series of analytic functions of known mathematical character, a best fit to amplitude vs. horizontal offset variations of a gather of said corrected traces, said gather of traces being identified with a common centerpoint location and a set of progres-sively changing horizontal offset values;
(e) predicting near and far amplitude vs. time trace projections for said gather of corrected traces at new offset locations based on said best fitting analytic func-tion, said predicted near and far offset trace projections being identified with offset locations falling on opposite sides of said set of changing horizontal offset values;
(f) displaying a first series of said trace projec-tions of step (e) associated with near offset locations, side-by-side with a second series of trace projections also of step (e) associated with far offset locations, said first and second series of displayed traces all being associated with at least the same general common groups of centerpoints so that progressive change in a high-inten-sity amplitude event in said displayed traces is identi-fied as a function of progressive change in centerpoint values.

2. The method of Claim 1 in which said one of said series of analytic function of known mathematical charac-ter of step (e) is selected from a group of linear and quadratic equations of the form:
A(x) = C0 + C1 x; A(x) = C0 + C2 x2; and A(x) = C0 + C1 x + C2 x2 where A(x) is the amplitude of the projected trace as a function of offset x; and C0, C1 and C2 are constants determined by conventional seismic processing steps.

3. The method of Claim 2 in which selection of said one analytic function of known mathematical character of step (d) is based on a least squares fit, of said best fitting function to said amplitude vs. offset variations of said gather of corrected traces.

4. The method of Claim 2 further characterized in that step (e) of predicting near and far amplitude vs.
offset trace projections for each of said gathers of corrected traces is determined by solving said best fitting analytic function for preselected near and far offset values, using constants determined by conventional processing steps.

5. The method of Claim 4 in which each of said near amplitude vs. offset trace projections of step (e) is determined by solving said one selected analytical func-tion for a near offset location X = 0 and using constants determined by conventional processing steps.

6. The method of Claim 4 in which each of said far amplitude vs. offset trace projections of step (e) is determined by solving said one selected analytical func-tion for the far offset location x = the mute offset loca-tion for CDP processing of said corrected traces.

7. The method of Claim 4 in which each of said far amplitude vs. offset trace projections of step (e) is determined by solving said best fitting analytical func-tion for the far offset location x = the offset location used for CDP processing of said corrected traces so as to provide for an emergence angle that produces minimum acceptable trace distortion.

8. The method of Claim 7 in which said emergence angle of minimum acceptable trace distortion is between 40-50 degrees measured from a vertical normal to a hori-zontal rejecting horizon.

9. The method of Claim 1 with the additional step of:
(g) determining the lithologic character of the strata based on the direction of the progressive change in the amplitude event between said first and second series of trace projections.

10. The method of Claim 9 in which step (g) is fur-ther characterized by the substeps of (a) observing that the amplitude event of interest increases from said first series of traces to said second series, and (b) concluding that the lithologic character of the strata is more likely than not a sandstone underlying an impervious shale.

11. The method of Claim 9 in which step (g) is fur-ther characterized by the substeps of (a) observing that the amplitude event of interest decreases from said first series of traces to said second series, and (b) concluding that the lithologic character of the strata is more likely than not a limestone underlying an impervious shale.

12. A method for converting an original multitrace seismic record into an improved section having increased capability as to fluid hydrocarbon-bearing potential and/or lithologic nature of high-intensity amplitude events related to reflections from subsurface strata, said improved section being composed of a plurality of ampli-tude-versus-centerpoint-and-time traces, said original record consisting of a plurality of multitrace seismic traces of amplitude-versus-horizontal coordinate-and-time, each of said traces constituting energy derived in asso-ciation with a particular source-detector pair of known horizontal offset and of known centerpoint location, and representing, in part, event reflections from said subsur-face strata, said conversion comprising the steps of:
(a) classifying said original traces on the basis of common but progressively changing horizontal offset values and common but progressively changing common centerpoint locations, whereby each resulting trace is identified by a centerpoint location common to at least another trace and a known horizontal offset value;
(b) determining among a series of analytic functions of known mathematical character, a best fit to amplitude vs. offset variations of said each resulting trace and said at least another trace;
(c) predicting near and far amplitude vs. offset trace projections for said resulting trace and another trace at new offset locations based on said best fitting analytic function, said predicted near and far offset trace projections being identified with offset locations falling on opposite sides of said set of changing horizon-tal offset values;

(d) displaying a first series of said trace projec-tions of step (c) associated with near offset locations, side-by-side with a second series of trace projections also of step (c) associated with far offset locations, to form at least a segment of said improved section; said first and second series of displayed traces all being associated with at least the same general common group of centerpoints so that progressive change in a high-inten-sity amplitude event in said displayed traces is identi-fied as a function of progressive change in centerpoint values.

13. The method of Claim 12 in which said best fitting analytic function of known mathematical character of step (b) is selected from a group of linear and quadratic equa-tions of the form:
A(x) = C0 + C1 x; A(x) = C0 + C2 x2; and A(x) = C0 + C1 x + C2 x2 where A(x) is the amplitude of the projected trace as a function of offset x; and C0, C1 and C2 are constants determined by conventional seismic processing steps.

14. The method of Claim 13 in which selection of said best fitting analytic function of known mathematical character of step (b) is based on a least squares fit, of said function to said amplitude vs. offset variations of said gather of corrected traces.

15. The method of Claim 13 further characterized in the step (c) of predicting near and far amplitude vs. off-set trace projections for each of said resulting trace and said another trace is determined by solving said best fitting analytic function for preselected near and far offset values, using constants determined by conventional processing steps.

16. The method of Claim 15 in which each of said near amplitude vs. offset trace projections of step (c) is determined by solving said best fitting analytical func-tion for a near offset location X = 0 and using constants determined by conventional processing steps.

17. The method of Claim 15 in which each of said far amplitude vs. offset trace projections of step (c) is determined by solving said best fitting analytical func-tion for the far offset location x = the mute offset loca-tion for CDP processing of said corrected traces.

18. The method of Claim 15 in which each of said far amplitude vs. offset trace projections of step (c) is determined by solving said best fitting analytical func-tion for the far offset location x = the offset location used for CDP processing of said corrected traces so as to provide for an emergence angle that produces minimum acceptable trace distortion.

19. The method of Claim 18 in which said emergence angle of minimum trace distortion is between 40-50 degrees measured from a vertical normal to a horizontal reflecting horizon.

20. The method of Claim 12 with the additional step of (e) determining the lithologic character of the strata based on the direction of progressive change in the amplitude event common to said traces.

21. A method for determining hydrocarbon-bearing potential and/or lithology of strata in the earth using high-intensity amplitude events in seismic records, com-prising the steps of:
(a) generating seismic data, including a record of signals from acoustic discontinuities associated with said strata of interest by positioning and employing an array of sources and detectors such that centerpoints between selected pairs of sources and detectors form a series of centerpoints along a line of survey, said recorded signals being the output of said detectors;
(b) by means of automated processing means, static-ally and dynamically correcting said recorded signals to form corrected traces whereby each of said corrected tra-ces is associated with a centerpoint horizontally midway between a source-detector pair from which said each corrected trace was originally derived;
(c) by means of automated processing means, indexing said corrected traces so that each of said corrected tra-ces is identified in its relationship to neighboring tra-ces on the basis of progressive changes in common center-point location;
(d) determining from among a series of analytic func-tions of known mathematical character, a best fit to amplitude vs. horizontal offset variations of a gather of said corrected traces, said gather of traces being identi-fied with a common centerpoint location and a set of pro-gressively changing horizontal offset values;
(e) predicting near and far amplitude vs. time trace projections for said gather of corrected traces at new offset locations based on said best fitting analytic func-tion, said predicted near and far offset trace projections being identified with offset locations falling on opposite sides of said set of changing horizontal offset values;
(f) generating a first envelope of said trace ampli-tude projections of step (e) associated with near offset locations and a second amplitude envelope of said trace projections of step (e) associated with far offset loca-tions and subtracting the two envelopes one from the other to form a difference envelope;
(g) displaying said difference envelope of step (f) so as to depict amplitude vs. time change as a function of centerpoint coordinate so that progressive change in a high-intensity amplitude event in said displayed traces is identified as a function of progressive change in center-point values.

22. Method of Claim 21 in which step (e) of predict-ing near and far trace projections is in accordance with solution of the general equation A(x) = Wj Aj in matrix format, where:
Wj is a function that varies with the selected linear or quadratic equation that best fits with the said ampli-tude vs. time variations of the trace gathers, and Aj is the amplitude of the gathers for the time samples T1....Tj.

23. Method of Claim 22 where step (e) of predicting projection amplitudes provides that such projections be for an offset location at Xp and wherein Wi in the general equation A(x) = Wi Ai is equal to:

24. A method for converting an original multitrace seismic record into an improved section having increased capability as to hydrocarbon-bearing potential and/or lithologic nature of high-intensity amplitude events related to reflections from subsurface strata containing the hydrocarbons, said improved section being composed of a plurality of amplitude-versus-centerpoint-and-time traces, said original record consisting of a plurality of multitrace-seismic traces of amplitude-versus-horizontal coordinate-and-time, each of said traces constituting energy derived in association with a particular source-detector pair of known horizontal offset and of known centerpoint location, and representing, in part, event reflections from said subsurface strata, said conversion comprising the steps of:
(a) classifying said original traces on the basis of common but progressively changing horizontal offset values and common but progressively changing common centerpoint locations, whereby each resulting trace is identified by a centerpoint location common to at least another trace and a known horizontal offset value;

(b) determining with regard to a series of analytic functions of known mathematical character, that one of said series is the best fit to amplitude vs. time varia-tions of said each resulting and said at least another trace;
(c) predicting near and far amplitude vs. time trace projections for said resulting and another traces at new offset locations based on said one, best fitting analytic function, said predicted near and far offset trace projec-tions being identified with offset locations falling on opposite sides of said set of changing horizontal offset values;
(d) generating a first series of trace amplitude projections vs. time of step (c) associated with near offset locations, and a second series of trace amplitude projections vs. time associated with far offset locations and subtracting increments of said first and second series normalized to the same time sample, one from the other to form at least a segment of said improved section;
(e) displaying said improved section depicting ampli-tude change as a function of time and centerpoint coor-dinate so that progressive change in a high intensity amplitude event in said displayed traces is identified as a function of progressive change in centerpoint values.

25. The method of Claim 24 in which said one of said series of analytic function of known mathematical charac-ter of step (b) is selected from a group of linear and quadratic equations of the form:
A(x) = C0 + C1 x; A(x) = C0 + C2 x2; and A(x) = C0 + C1 x + C2 x2 where A(x) is the amplitude of the projectd trace as a functin of offset x and C0, C1 and C2 are constants deter-mined by matrix algebra.

26. A method for determining valuable characteristics of strata in the earth using high intensity amplitude events in seismic records, comprising the steps of:

(a) generating seismic data, including a record of signals from acoustic discontinuities associated with said strata of interest by positioning and employing an array of sources and detectors such that centerpoints between selected pairs of sources and detectors form a series of centerpoints along a line of survey, said recorded signals being the output of said detectors;
( b) by means of automated processing means, static-ally and dynamically correcting said recorded signals to form corrected traces whereby each of said corrected traces is associated with a centerpoint horizontally mid-way between a source-detector pair from which said each corrected trace was originally derived;
(c) by means of automated processing means, indexing said corrected traces in two dimensions whereby each of said corrected traces is identified in its relationship to neighboring traces on the basis of progressive changes in horizontal offset value versus progressive changes in common centerpoint location;
(d) weighting said series of traces of step (c) by semblance coefficients wherein after a series of normalized ratios of output-to-input energy is generated by stacking, events in the traces associated with a limited number of phases are better indicated;
(e) displaying said weighted traces or representations of said weighted traces of (d), whereby progressive change in a high-intensity amplitude event of said displayed traces or representations of said traces is identified as a func-tion of progressive change in said horizontal offset values.