3.- identification of lithology in the gof

Identification of lithology in the Gulfof Mexico

FRED HILTERMAN and JOHN W. C. SHERWOOD, Geophysical Development Corporation, Houston, TexasROBERT SCHELLHORN, Chieftain International, Dallas, TexasBRAD BANKHEAD, ORYX, Dallas, TexasBRIAN DEVAULT, Colorado School of Mines, Golden, Colorado

n a small town outside of Houston,a local rancher was overh e a rd saying,Do you have any 3-D seismic acro s syour place? You ought to get some,because it tells you exactly whatsdown there and where to drill.

Yes, the transfer of technologyhas been accelerated by new elec-t ronic media such as the Internet, butis it possible that it bypassed the geo-physicists?

Maybe the rancher was looking atbright spots plotted in red. Suchresults are possible but not guaran-teed. Throughout the Tertiary basinsin the Gulf of Mexico (GOM) area reas where acoustic impedance val-ues of shales and gas sands area p p roximately equal. This meansh y d rocarbon zones do not appear asbright spots and are difficult to detectwith conventional 3-D seismic data.F u r t h e r m o re, in some areas, geo-physicists have had no success usingAVO for predicting exactly where todrill. This normally occurs when therock properties are not calibrated tothe various AVO attributes.

To resolve this dilemma, a 3-DAVO study was conducted utilizingn u m e rous well-log suites, core analy-ses, and field production histories.With the inclusion of anisotro p i ce ffects, a robust AVO analysis basedon a lithologic model was possible.Results from this study are illustrat-ed in Figure 1: A conventional 3-Dsection with the AVO analysis over-plotted in red and yellow. Corre l a t i o nto the well-log curves and the fieldp roduction histories indicates that allred and yellow events are associatedwith proven hydrocarbon zones.Could this be the 3-D seismic that therancher was talking about?

It is obvious that the re f l e c t i o namplitudes on the conventional 3-Dseismic do not identify lithology ifthe red and yellow events are trulyh y d rocarbon events. However, as theremainder of this article will show, insome environments, the petrophysi-cal AVO model can be constrained sothat reflections from very clean wet

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Figure 1. Conventional migrated section with AVO anomalies super-imposed as red and yellow events that represent known hydrocarbon reservoirs.

Figure 2. Suite ofsonic logs across Ter-tiary basin (upper)and synthetic strati-graphic section gen-erated by the normal-incidence reflectioncoefficient equation(lower). Chronostrati-graphic surfaces arenumbered. (AfterVail, 1977).

Figure 3. Poissonsratio curves for shaleand sand as a functionof P-wave velocity. IfVp,sand > .84Vp,shale , thensand

< shale , a conditionthat occurs in most ofGOM.

February 1998 THE LEADING EDGE

sands and gas sands overshadow allother reflections. These dominantlithostratigraphic reflections arerelated to Poissons ratio.

Chronostratigraphic and lithostrati-graphic reflections. Vail and col-leagues at Exxon presented the basicprinciples underlying seismic strati-graphy 20 years ago in AAPG Memoir2 6 . F i g u re 2, one of the most re m e m-b e red illustrations from that work,displays several sonic logs across aTertiary basin in South America alongwith three chronostratigraphic orequal-time surfaces numbered 15, 10,and 8. Of importance is that chro n o s-tratigraphic surface 8 cuts rightt h rough a major sand deposit whichoverlies an unconformity. The lowerportion of Figure 2 shows a series ofnormal-incidence synthetic seismo-grams generated from the sonics.What astounded geophysicists whenthis synthetic was first presented wasthat the reflection events follow thec h ronostratigraphic surfaces and notthe upper and lower surfaces of thesand package which would be thelithostratigraphic surfaces. From thisexample and the many that have beenp roduced since 1977, it was conclud-ed that the normal-incidence sectionand conventional seismic data basi-cally consisted of chro n o s t r a t i g r a p h-ic reflections. It should be noted thatthis conclusion results from empiricalobservations and not a rigid theore t-ical model.

Shortly afterward (1982), anotherExxon geoscientist (Paul Tu c k e r )warned (in Pitfalls Revisited) thatstacking enhances continuity andparallelism of the reflection, ... butover-stacking can destroy the geolo-gy. ... Stacking can also distort thestratigraphy ... thus playing havocwith successful stratigraphic map-ping. These astute observationsw e re made before the advent of AV Oand before the information contentof the reflection stack was fullyunderstood. Is it possible that, becauseof the long offsets employed in todaysseismic, that a mixing of two petrophys -ical properties acoustic impedanceand Poissons ratio leads to strati -graphic distortion? Are chro n o s t r a t i -graphic and lithostratigraphic re f l e c t i o n sbeing mixed together?

Petrophysical model. The relation-ship of chronostratigraphic andlithostratigraphic events to thereflection amplitude is difficult toenvision if the exact Zoeppritz equa-tion is examined.

H o w e v e r, a decade ago Shuey(GEOPHYSICS, 1985) presented a lin-ear approximation of the reflection-coefficient equation that was recent-ly modified by Verm and Hilterman(TLE, August, 1995) to:

RC() NI cos2() + PR sin2()

where

NI = Normal-incidence reflectivity =

(2V2- 1V1)/(2V2+ 1V1), PR = Pois-son reflectivity = (2- 1 )/(l- avg)2 ,and , V and are respectively thed e n s i t y, P-wave velocity and Pois-


Figure 4. Suite of well-log curves in study area. While the Poissons ratiocurve correlates with the SP curve, the acoustic-impedance and sand-per-centage curves do not correlate.

Figure 5. Crossplot of ln [acoustic impedance] versus Poissons ratio.Quick-look prediction tool: vertical distance between two lithologic pointsrepresents NI while horizontal distance represents PR.

0.14 Poissons Ratio 0.44


sons ratio for the lower medium (2)and the upper medium (1), and avgis (2+1)/2.

This equation provides usefulinsight into the AVO response, and itis often used as the model for esti-mating NI and PR from seismic CDPgathers. The main benefit is that theresulting PR can be thought of as asignal that reflects from the earthsPoissons ratio profile. Since Vail re l a t-ed NI to chro n o s t r a t i g r a p h y, we ask,Can it be that PR is related to lithos-tratigraphy; i.e., sand versus shale?Verm and Hilterman, in fact, notedhow the Poissons ratio curve in asand-shale sequence closely re s e m-bles the SP curve, a primary lithos-tratigraphic tool of the log analyst.The correlation between SPand Pois-sons ratio curves can be explained byexamining Castagnas empirical Vp-to-Vs relationships (Figure 3).

An interesting observation fromFigure 3 is that sand appears to havea Poissons ratio that is consistentlysmaller than shales Poissons ratio.This is similar to an SP curve wherethe sand value falls beneath the shalebase line. From the diagram, for aPoissons ratio curve to resemble anS P curve, the P-wave velocity ofsand and shale should be approxi-mately the same. If shale and sandhave the P-wave velocities as depict-ed by points A and B in Figure 3,then the Poissons ratio for sand isless than shale. This is similar to anS P relationship. However, as thesand P-wave velocity decreases fro mpoint B to C, the Poissons ratio dif-ference between sand and shale dis-appears. Thus, for the correlation ofthe SP and Poissons ratio to be sim-ilar, the sand P-wave velocity mustbe greater than .84 of shales P-wavev e l o c i t y. This condition exists formost of the GOM. In short, the Pois-sons ratio curve indicates lithologysimilar to an SP curve, and thusreflection amplitude associated withthe Poisson reflectivity will be lithos-tratigraphic. Also, as the Ve r m -Hilterman equation indicates, theconventional seismic stack doesindeed mix the lithostratigraphic PR,with the chronostratigraphic NIespecially in a Class 2 environmentwhere NI is small.

The PR contribution to the re f l e c -tion amplitude is not significant untillarger incidence angles are reached.When the sourc e - receiver offset isthe same as the depth of investiga-tion, the incidence angle is approxi-mately 30. At this angle, 75% of the


Figure 6. Migrated CDP gather and isotropic AVO synthetic from well atsame location. Both are NMO-corrected, based on isotropic media. Offsetsrange from 1000 to 20 000 ft.

Figure 7. Migrated CDP gathers, NMO-corrected with isotropic equation(upper) and anisotropic equation (lower). Offsets range from 1000 to 20 000 ft.


reflection amplitude (according tothe Verm-Hilterman equation) isf rom chronostratigraphy (NI) and25% from lithostratigraphy (PR).H o w e v e r, at 60, the situation isopposite because 25% is NI and 75%is PR. Thus, if lithology estimation isthe goal, it is desirable to re c o rd seis-mic data at angles approaching 60.

If reflections at angles of 60 aredesired and assuming that the criti-cal angle has not been reached, thep e t rophysical model described bythe Verm-Hilterman equation mustbe reviewed. A h i g h e r- o rder termwhich can be approximated by 1/2 [(V2 - V1)/(V2 + V1)] (tan2- sin2)was dropped from the right side oftheir approximation. This term cantbe ignored unless the change in P-wave velocity across the interface issmall. Thus, the direct evaluation oflithology from the large offset reflec-tion amplitude is modeled for smallvelocity variations which occurfor Class 2 AVO anomalies.

Well-log data. The study are ainvolved Tertiary rocks that are com-monly found in the transition zone ofo ff s h o re Texas and Louisiana. Figure4 illustrates a typical suite of well-logcurves from the area. The SP c u r v eresembles the Poissons ratio curveshown next to it. Pay zones aro u n d8000 ft are indicated by red re c t a n g l e s .The acoustic impedance curve that isoverplotted on the sand-perc e n t a g ecurve has little character re s e m b l a n c eto it, suggesting that acoustic imped-ance is not a good indicator of lithol-ogy in this enviro n m e n t .

In order to calibrate this well tothe AVO response, a crossplot of thenatural log of acoustic impedanceversus Poissons ratio for the depthinterval 6100-9000 ft was generated(Figure 5).

With the normal-incidence re f l e c-tion coefficient expressed as NI = . 5 [ 1 n (V )2 - 1n(V )1], the vertical dis-tance on the graph linearly relates toNI. The Poissons ratio axis can thenbe scaled so that a relative re l a t i o n-ship of NI to PR can easily beobtained. For instance, the verticaldistance (NI) between the center ofthe shale points and the center of thegas-sand points is small compared tothe horizontal distance (PR) betweenthese points. This distance re l a t i o n-ship suggests that the NI for ashale/gas sand interface will be smallc o m p a red to its corresponding PR.Also, the vertical distance (NI) fro mthe shale center point to the gas-sand


Figure 8. Anisotropic ray-theory AVO synthetic and migrated CDP gathersat a well site with both anisotropic and isotropic NMO corrections.

Figure 9. Conventional migrated section (upper), estimated PR section byinversion (middle), and estimated PR section by large-angle stack (lower).


center point is about the same as thevertical distance (NI) from the shaleto the wet sand. This means brightspots will not be evident. However,the horizontal distance (PR) for ashale/gas sand interface is appro x i-mately four times larger than the hor-izontal distance (PR) for a shale/wetsand interface. This indicates that PR,and not NI, will diff e rentiate litholo-g y. The ln[V] versus c rossplot pro-vides a quick-look method of cali-brating NI and PR to variouslithologic interfaces.

Anisotropic eff e c t . In an effort to sta-bilize the extraction of PR from aCDP gather, offset distances whichwere greater than depth (incidenceangles greater than 30) weredesired. In Figure 6, a 3-D migratedC D P gather at a well location isshown beside the wells AVO syn-thetic response. The model wasi s o t ropic and NMO-corrected withthe wells RMS velocity. At 2.25 s ( 8000 ft), the models 14 000-ft off-set trace exhibits an NMO overcor-rection of 45 ms (caused by thei s o t ropic ray bending). The field datahad an overc o r rection at the sameo ffset of 125 ms. This additionalovercorrection (125 ms - 45 ms) wasidentified as an anisotropic effect. Inessence, the horizontal velocity isfaster than the vertical velocity.

It is believed that the media aredominantly transversely isotro p i c(TI). 3-D fields of both velocity andanisotropy are obtained from NMOanalyses and can then be applied inthe NMO, DMO and migration pro-cessing steps.

F i g u re 7 presents three CDPgathers with conventional (isotro p i c )NMO and anisotropic NMO correc-tions. An interesting effect in the fartraces is the reduction of NMOstretch when anisotropy is includedin the NMO correction. Often, theNMO overc o r rection on the fartraces is not observed because theCDP gathers are muted at the linewhich is equivalent to offset = depth.H o w e v e r, as the Ve r m - H i l t e r m a nequation and the crossplot indicate,the reflections on the right side of themute line contain information aboutlithology that needs to be preserved.This lithologic content can be veri-fied by AVO modeling.

Well-log curves along with thea n i s o t ropic properties measured fro mthe 3-D seismic were used to generatethe AVO anisotropic synthetic shownin Figure 8. To the right of the syn-thetic is the anisotro p i c - p ro c e s s e d

C D P gather at the well location. Tw ogas zones are evident on the SP a n dresistivity logs. The thickness of theupper gas sand (at 2.25 s) is 40 ft whilethat of the lower sand (2.39 s) is 35 ft.O ffset traces up to 16 000 ft wereusable in the CDP g a t h e r. Because thea n i s o t ropy in this area causes thew a v e f ront to flatten from its isotro p-ic spherical shape, the incidence angleat 2.39 s on the maximum offset traceis 50 for anisotropic modeling, whilei s o t ropic modeling predicts 60. Thismeans critical angle reflections occuron traces with larger offsets than con-ventionally assumed.

A n i s o t ropic AVO synthetics, inplace of 1-D synthetics, offer severali n t e r p retational benefits. First, theAVO synthetics correlate to the CDPgathers, especially if the thick cleansands and gas sands are matched atthe far traces. This is evident by com-paring the AVO synthetic to the fieldCDP gather in Figure 8. Also, whenthe acoustic impedances of the sandand shale are almost equal, smallerrors for the sonic and density val-ues in the uninvaded zones have sig-nificant impact on the 1-D synthetic.Not only can the magnitude of thereflection be several times off, butalso the polarity of the reflection canbe reversed, thus making it difficultto match the 1-D synthetic to thefield data. However, the Poissonsratio assigned to a depth interval iss t rongly dependent on the more

robust estimate of lithology from thegamma and SP logs. Thus, on theAVO synthetic, the far-offset tracesare more likely to show the correctcorrelation with the field data thanthe 1-D normal-incidence synthetic.As an experiment, try tying an SP l o gdisplayed in time to the far- o ff s e ttraces in a CDP gather (far- o ff s e ttraces offset > 1.5 depth).

Field data. The study area was con-fined to one off s h o re block (ninemi2). A typical three-mile line acrossthe block is displayed in the upperportion of Figure 9. This conven-tional 3-D migrated section includesreflections with incidence angles of0-26. Two control wells are on thisline. Because of the small NI com-pared to the PR (as predicted fromthe well-log crossplot), this sectionexhibits a mixture of both NI and PRevents, accounting for some of thewormy events. Several eventshave amplitudes that are larger thanthe background reflectors. However,none of these bright events are asso-ciated with the two known gas zonesin well B.

The middle section of Figure 9 isan AVO inversion for PR based onthe Verm-Hilterman equation. Theoverplotted red and yellow eventsa re associated with those amplitudescalibrated to be gas-sand re f l e c t i o n s .Near well B, this PR section has al a rge reflection for the upper gas


Figure 10. Conventional migrated section (upper) and estimated PR sectionby large-angle stack. Red-yellow events are well-log calibrated as gas-sandreflections.


zone around 2.55 s, but evidence ofthe deeper gas zone near 2.98 s ismissing. This is labeled as MI forMissing Indicator. Another MI occursnear well D. What is also discourag-ing about this PR section is that abright reflection occurs at 2.66 s atwell B. This reflection appears in asand-poor interval just below theonset of geopre s s u re. This is a FalseIndicator (FI) of hydro c a r b o n s .

The existence of missing andfalse hydrocarbon indicators fro mthe AVO inversion of PR based onthe Verm-Hilterman equation sug-gested that a more robust estimatorof PR was needed. This is shown inthe lower portion of Figure 9. It is alarge-angle stack that included inci-dence angles (26-55). From the cor-relation to the many wells in thearea, the red and yellow events canbe tied to known production. Nofalse indicators nor missing indica-tors occurred at well locations. Thei m p rovement of the larg e - a n g l estack section over the PR inversionsection can be attributed to the factthat the inversion uses differences ofamplitudes to estimate PR. Howev-er, the large-angle stack would nothave been a good estimator of PR ifthe magnitude of NI and PR were thesame and also if the large off s e tangles were not used. Rememberthat the contribution of PR becomeslarger than NI after 45. In short, forh y d rocarbon identification, the PRestimate from large-angle stacks isnot always better than a PR inver-sion based on a mathematical model.It depends on the magnitude rela-tionship of NI to PR in the local area,and this should be evaluated beforeany interpretation of seismic AV Oattributes is conducted.

The seismic line in Figure 10 isnear the one in Figure 9. The upperportion contains the conventionalstack, while the lower portion is thelarge-angle stack. Two control wellsare on this line, and two are project-ed onto the line. The top of geopres-sure once again occurs around 2.6 s.

No false indicators or missingindicators of gas zones are on thelower section. What is interesting isthe high that appears between wellsF and D at approximately 2.8 s. Orig-i n a l l y, this was a prospect to bedrilled. However, subsequent inter-p retation of the PR 3-D volumechanged this decision. The twoevents at 2.8 s near wells F and D arenow interpreted to be two separatechannels that cut into the flanks of anexisting topographic feature. The

crest of this feature does not appearto be sand prone.

The lower portion of Figure 10 isa good re p resentation of lithologywhile the upper portion containsboth lithostratigraphic and chronos-tratigraphic reflections. In fact, Fig-ure 1 is a combination of the upperportion of Figure 10 with the red andyellow events from the lower portionof Figure 10 superimposed.

F i g u re 11 shows time slices at 2.54s across both the conventional 3-Dvolume and the large-angle stack 3-Dvolume. The upper portion is fro mthe conventional 3-D volume whilethe lower is the large-angle stack.Both time slices have similar pat-

terns, but only the large-angle stackp roperly depicts the known limits ofthe major reservoir in the northeast-ern portion of the study are a .

D i s c u s s i o n . When a wet sand is veryclean, its Poissons ratio lies betweenthat of a gas sand and a slightly shalysand. Also, clean sands tend to beblocky in appearance on the SP logand thus do not suffer from a reduc-tion in PR amplitude caused by atransitional shaliness. These obser-vations suggest that caution shouldbe exercised when evaluating highamplitude PRs on the lithologic sec-tion as they can be clean-sand reflec-tions. Normally, however, clean wet


Figure 11. Time slice at 2.54 s from conventional 3-D volume (upper) andequivalent time slice from large-angle stack 3-D volume (lower). Knownfield is depicted by red in northeastern part of block (lower time slice).


sands can be differentiated from gassands by crossplotting the NI versusthe PR volumes as described byVerm and Hilterman.

It was fortuitous that this are ahad numerous gas reservoirs andalso had several clean blanket sands.At the same time, without the avail-ability of the 3-D long-offset seis-mic data in a good reflection area, the application of the anisotropic p rocessing would not have beenattempted. The repeated high-ampli-tude reflections throughout the blockfrom the very clean sands and gassands allowed the anisotropic factorto be analyzed with NMO corre c-tions. Other reflections were buriedin the noise on the far-offset traces.

One obvious omission in thisarticle is the contribution ofa n i s o t ropy to the reflection coeff i-cient equation. Using the estimate ofthe function from the NMO analy-sis and using the available sonic log,low frequency estimates of theThomsens anisotropic parameters and are obtainable. These two timefunctions are then adjusted using theshale volume curve to force thea n i s o t ropy to reside in the shalezones and to allow the sand zones tobe basically isotropic. This pro c e d u re

provides the additional parametersneeded to generate TI AVO synthet-ics. However, no compensation hasbeen assigned to the inversion algo-rithms. This is a project for futureinvestigation.

C o n c l u s i o n s . When the acousticimpedance of sands and shales arenearly equal, the Poissons ratiocurve is similar to the SP curve. Inthis situation, the amplitude on thelarge-angle traces is essentially thePoisson re f l e c t i v i t y, which is an indi-cator of lithology. The conventionalstack, especially in Class 2 environ-ments, will be composed of chronos-tratigraphic and lithostratigraphicreflections. Assuming shale to be thebounding media, PR reflections fro mgas sands have the highest ampli-tudes, very clean wet sands have thenext highest amplitude, and shalywet sands are weaker. By calibratingthe color scale to highlight the PRamplitudes, a section results that def-initely fits the tale of the local ranch-er it tells you exactly whatsdown there and where to drill.

H o w e v e r, a geophysicist willstill be needed to make sure therancher is in the right class of AV Oa n o m a l i e s .

Suggestions for further reading.There have been numerous publica-tions in GEOPHYSICS and TLE fromthe Center for Wave Phenomena,Colorado School of Mines coveringa n i s o t ro p y. Ilya Tsvankins article, P -wave signatures and notation for trans -versely isotropic media: An overviewcontains the basic principles and ref-e rences necessary for anisotro p i cseismic processing. The connectionof seismic to the rock properties canbe found in the excellent review byCastagna et al. Rock physics The linkbetween rock properties and AV Oresponse in Offset-Dependent Reflectiv -ity Theory and practice of AVO analy -sis, SEG IG No. 8.

Acknowledgments: We thank Fairfield Indus -tries for its cooperation and permission toshow the seismic from its shallow-water 3-Dsurvey. At GDC, Mark Wilson provided thep e t rophysical analysis; Connie Van Schuyver,the seismic data processing; Martin Wood,the software code, and, Jim DiSiena, sugges -tions to the manuscript. Finally, GDC appre -ciates the opportunity to apply the excellentanisotropic work published by Thomsen andTsvankin.

C o r responding author: Fred Hilterman,[email protected]


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3.- identification of lithology in the gof

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