interpretation of four-component seismic data in a gas

Although the Gulf of Mexico is a mature producing basin,additional reserves continue to be discovered via applica-tion of new geophysical technologies. Contributing to cur-rent record success rates are 3-D seismic data, powerfulworkstations with interpretation software, direct hydrocar-bon indicators, AVO, and prestack depth migration. Recently,marine four-component (4-C) methods involving simulta-neous recording of compressional (P-wave) and convertedshear (C-wave) data have started to gain acceptance (seeTLE’s October 1999 special section). Although applicationsof 4-C technology are numerous, the best known are whereupward seepage of gas from hydrocarbon accumulationsresults in a “cloud” that absorbs P-wave energy and causessignificant velocity-related distortions. The combination ofthat and other negative effects can obscure the deeper sub-surface image, making traditional interpretation difficult.

This paper focuses on a field on the southern central partof the offshore Gulf of Mexico shelf that exhibits gas cloudproblems. The following discussion covers the geology ofthe field and summarizes results from three key wells thatwere drilled in 1998 and early 1999 (two producers and onedry hole). It next describes the analysis and interpretationof the combined P-wave and C-wave data resulting fromfour-component acquisition and closes with comments con-cerning the future of such applications in the Gulf of Mexico.

Background. The field, a NE/SW structure in South MarshIsland Blocks 141 and 144, consists of faulted highs relatedto deep-seated salt movement (Figure 1). It was discoveredin 1984 by Marathon, whose Aplatform ultimately produced52 billion ft3 of gas from four Pleistocene inner shelf sand-stones at depths of 2100-6400 ft subsea. More than half ofthat production was from the deepest E sand reservoir. Datafrom five wildcats and 10 development wells provided excel-lent subsurface control with reliable sand correlations andeasily identifiable fault cuts as of 1998.

Many original pay zones were expressed on 1980’s 2-Dand 1995 speculative 3-D data sets as high-amplitude anom-alies (“bright spots”) which defined the original productivelimits. Conversely, as shown in Figure 2a, areas of knownpay were attenuated or completely obscured by shallow gas,e.g., 0.34 s (900 ft subsea), 0.46 s (1300 ft subsea), and 0.58 s(1600 ft subsea).

The quality of the seismic image on both 2-D and 3-Dcompressional data greatly deteriorated below the AB pro-ducing horizon at 0.7 s (2000 ft subsea). Among the phe-nomena observed were time-structural sags (which gavefalse impressions of the depth structure), attenuation ofreflections/faults, and a loss of clearly defined amplitudeanomalies below 0.8 s (2300 ft subsea). The effect is pro-gressively more severe until about 1.5 s (5000 ft subsea),after which data quality improves slightly, probably due tothe increase in S/N ratio resulting from the stacking of faroffsets.

In 1998 Hall-Houston Oil Company, and later Newfield

Exploration Company, drilled eight new wells and set twonew platforms. Although most new drilling was into poordata zones, this work resulted in the identification of 10 newcommercial pay sands, all above the previous major E sandpay. Drilling was done in spite of poor 3-D seismic data qual-ity because the abundant well control gave confidence in theoverall geologic interpretation. The initial interpretation tech-nique in the poor data areas consisted of extrapolating thedip rates from offstructure wells and establishing a basicstructural shape. One intermediate mapping level had a fairamplitude anomaly that, although unusual in time-structuralappearance, areally resembled a classic fault trap closure. Akey step was to interpret a simple depth structure and thenextrapolate it both shallower and deeper along the maintrapping fault for other possible reservoirs.

In June 1999, PGS acquired a pair of intersecting, dip-orientated 2-D seismic lines across the overall structure, tyingthree recent key wells and one older well for control (Figure1). The goal was to determine if C-wave data would improvestructural imaging in the gas cloud area, and if any addi-tional stratigraphic insight could be gained using the com-bined P-wave and C-wave data.

The lines were shot using a 4-C ocean-bottom cable sys-tem; the cables were deployed without tension and were notdragged. A ship-towed 4770 inch3 source was fired at 37.5-m intervals into a split-spread with 50-m group intervals.This produced 160 fold in 25-m bins with offsets of 0-6000m. Each 4-C station had three separate units. The unit in the

400 THE LEADING EDGE APRIL 2001 APRIL 2001 THE LEADING EDGE 0000

Interpretation of four-component seismic data in a gas cloud area of the central Gulf of Mexico

THOMAS ENGLEHART, Englehart Energy, Houston, Texas, U.S.SANTI RANDAZZO, ALLEN BERTAGNE, and BILL CAFARELLI, PGS, Houston, Texas, U.S.

Figure 1. Structure map of SMI 141/144 area and thefour selected wells, plus the outline of the area thatexhibits gas cloud problems and the location of thetwo multicomponent lines discussed in this article.

center contained the mutually orthogonal horizontal com-ponents for detecting shear-wave energy. The other twounits, located a couple of meters on either side, containedthe vertical geophones and hydrophones for detecting com-pressional-wave energy. Housing the vertical and horizon-tal geophones in separate units eliminated any mechanicalcross-feed between them, a problem in some earlier 4-C sen-

sors. Currently, OBC systemsof the type used in this shootare limited in range to waterdepths of less than 150 m.However, other systems areavailable for collecting 4-Cdata in much greater waterdepths.

Line 1. This four-componentline tied two new wells oneither side of the southernpart of the graben in blockSMI 144. Both the new 2-DP-wave line (Figure 2a) andthe equivalent arbitrary linefrom a speculative 3-D vol-ume showed beds dippingaway from two majorgraben-forming faults, eachwith a water-bottom scarpexpression. Overall, the lineswere very similar, althoughthe larger-aperture 3-D dataresulted in better imaging ofthe steep dips around a deepsalt spire.

A high-amplitudetrough/peak “wedge” wason each upthrown side of thegraben with the larger,northern one at 0.78 s andthe smaller, southern one at0.62 s. These events corre-sponded to the 300-ftTrimosina A reservoir(known as the AB sand) thathad produced 3 billion ft3.The most pronounced timesag and seismic attenuationwere below the AB ampli-tude anomalies. Certainsands below AB show sub-tle increases in amplitudestrength (for example, AB-1,A-5, and B-1).

The northern AB anom-aly exhibited a high-ampli-tude leading trough andstrong basal peak reflectionsthat diminished toward thetrapping fault. Some ampli-tude decrease would beexpected as the AB pay col-umn increased above the 15-20 ms two-way time (~30 ft)“tuning” thickness resolu-tion of the seismic data. Thedecrease in amplitude alsocould have been due to

attenuation by the shallower gas hazards or to a lateralchange in the sand to a more fine-grained facies.

Structurally, the entire northern AB anomaly flattenedonce it entered the area beneath the shallower hazards. Thebasal peak of the anomaly paralleled the leading trough hor-izontally for 2000 ft, then reversed dip twice into a broad,concave-up time sag with a maximum 100 ms (two-way time)


a)

b)

Figure 2. (a) Line 1 P-wave section with interpretation. Note shallow gas hazards anddata deterioration beneath high amplitude events. (b) Line 1 C-wave (converted shearwave) section with interpretation.

trough/peak thickness. Possible interpretations of this fea-ture included a velocity distorted water contact, a shale-lined channel cut, or additional poorly imaged faultingcausing the dip reversals. Reflections below AB were simi-larly contorted with time structures paralleling the shape ofthe AB basal peak.

The southern AB anomaly was similar in amplitudestrength and also on an upthrown closure although boundedby a different fault. This fault also extended up to the seafloor,but there was much less shallow gas accumulation abovethe anomaly. The AB leading trough appeared to maintainthe offstructure dip rate all the way to its trapping fault withminimal decrease in amplitude strength. Its basal peak flat-tened once in the anomalous amplitude area with only a smalltime sag near the fault and a maximum trough/peak thick-ness of 55 ms. The amplitude anomaly envelope was fairlyuniform and had a good fit to structure. No offstructurewells were available in that fault block to define the true sub-surface dip rate.

Results from key wells on Line 1. The first recent well,Hall-Houston 144 4 (now 144 C-1) was drilled into the thick-est portion of the larger northern “AB” anomaly (well B in

Figure 3). It was chosen both as an attic play to a previousAB producer and to test the simple geologic concept of clo-sure and fill-up of deeper sands in a better structural posi-tion.

The speculative 3-D data mapping used a Block 141velocity survey that fit the unaffected, offstructure AB tops.This new well’s AB horizon top came in high to predrill esti-mates (at 2049 ft subsea) and encountered a 280-ft grossinterval, 90% sand with 140 ft of commercial gas and 70 ftof residual gas on water. The new top and gas column con-firmed that the offstructure 2.7� NW dip rate continued upinto the poor data zone. However, once under the shadowof the overlying gas hazards, the AB top P-wave reflectionhad flattened into the trapping fault and was 35 ms (117 ft)low to the new top, thereby confirming a time sag fromoverlying shallower gas.

The deeper AB-1, A-5, and B-1 sands had smaller but stillcommercial quantities of gas on water. After casing the holeto protect the AB and these deeper pays, a dipole sonic wasrun a year later in an attempt to collect both compressionaland true shear-wave sonic modes for synthetic seismogramcalibration of the PGS shooting. No dipmeter or densitytools were run before the casing had been set. The P-wave


Figure 3. Stratigraphic cross-section through four selected wells in SMI 141, 142, 144 area. Section is flattened ontop of “AB”. Sands are shown in yellow, gas pays in red.

synthetic (Figure 4a) fit both 2-D and 3-D P-waveseismic lines quite well. The low-impedance paysands all generated high-amplitude events. The ABanomaly had a good trough at the top of the payand a strong peak at the base of the sand but not atthe gas/water contact as was expected.

The southern AB anomaly, although smaller, wasviewed as a low-risk, simple tilted fault block witha normal-looking gas/water contact. The NewfieldExploration SMI 144 5 (well Ain Figure 3) was drilledas a straight hole in January 1999 at the time-thicklocation of the southern AB anomaly. It encounteredthe top at 1832 ft subsea with a gross sand intervalof 233 ft. However the sand had no indications ofhydrocarbons. No sonic or density logs were run inthis well. In short, the better of the two bright spotswith a similar-to-better structural setting and almostno shallow gas attenuation was the location thatturned out to be dry. This was a classic false DHIwith several, as yet, unanswered questions.Although small pays were found in the deeper seriesof sands, they were considered uneconomic and thewell was plugged and abandoned.

C-wave synthetic and line 1 C-wave seismic. The144 C-1 dipole sonic tool was unsuccessful in record-ing true shear-wave sonic because the thick lowvelocity zones throughout the well precluded thereturn of the shear-wave component. Using the goodquality compressional wave logs, an estimated shear-wave velocity was generated using the approachproposed by Krieff (1990). He demonstrated a qua-silinear relationship between the squares of acousticand shear-wave velocities in monomineralic assem-blages, and as an empirical relationship between theBiot coefficient and porosity.

The equations presented by Krieff offer signifi-cant advantages over those traditionally employedin geophysical modeling. The variables to recon-struct compressional-wave velocity are grouped sothat all variables except the framework term (Biotcoefficient) are available from log analysis. In con-trast the standard geophysical equations expressthe framework term in two variables. With only theframework term as an unknown and a series ofequations linking log analysis to rock moduli, theregrouped equation can be solved for the Biot coef-ficient without an empirical relationship.

This new shear-wave curve was the basis forpreparing the C-wave synthetic seismogram.Velocities of C-wave data were generally about one-half the velocity of the P-wave velocities. Both theC-wave synthetic and seismic lines were displayedto approximate the same time/depth relationshipsas the 2-D and 3-D P-wave lines using a 2:1 verticalcompression. Finally the C-wave data were rotated180° to the same polarity as the P-wave data. TheP-wave and C-wave synthetics were similar in fre-quency and the C-wave synthetic appeared to be aslightly stretched version of the P-wave synthetic(Figure 4b).

Without an obvious high amplitude trough eventrelated to the AB reservoir, the C-wave synthetic wasinitially less easy to position on the C-wave linethan the P-wave synthetic was to the P-wave seis-mic. However, forward modeling suggested thatthe largest C-wave impedance contrasts would still


Figure 4. (a) P-wave synthetic seismogram for Hall Houston 144 4(C-1). (b) Modeled shear-wave synthetic for the same well.

a)

b)

be generated by the AB and A-5 gas/water contacts withstrong, easily recognizable peaks and indeed major imped-ance contrasts were present at these boundaries on the C-wave synthetic. Although located beneath the syntheticseismogram, the E field pay could still be recognized easilyon the C-wave section by another very strong peak.

Working up the section from the E reflection and tyingreflector packages with the synthetic, the strong basal ABpeak was located again and confirmed. With the AB and Eidentified, the remaining sand packages between those mark-ers were defined on the C-wave section and confirmed bycomparison with the interpreted P-wave data. Together,

these key events allowed theC-wave synthetic to be fitonto the C-wave seismic andproduced a fine overall tie.

The initial appearance ofthe new seismic data (Figure2b) was striking, with excel-lent structural clarity andgood resolution across theentire line. Overall, the datahad a lower-frequencyappearance but seeminglymuch stronger signal-to-noise ratio. The C-wave ABsand was represented byfour trough/peak cycleswith a strong basal peak. Thethinner AB-1 had threecycles of equal energy andthe thinnest A-5 had onebroad cycle with a verystrong basal peak. The shalezones in between were low-amplitude trough doublets.As expected, no amplitudevariations were related tochanges in fluid content.There was no data wipeoutfrom shallow gas attenua-tion and good energy downto at least the same depth asthe longer-offset 3-D line.

The major graben-bounding faults were pre-sent in approximately thesame position as on the P-wave data, but there alsowere indications of somefaults not on the P-wavedata. Dip rates were uniformwithin fault blocks with noabnormal time sags or rever-sals. The C-wave seismic fitthe AB through A-5 tops andknown dip rates on the northside of the structure per-fectly, thus confirming itsability to correctly imagethrough overlying shallowgas zones. It was obviouslya large improvement for thestructural interpretationwithin areas of previouslypoor data. A jump tie waseasily performed to interpret

the southern fault block where there was little structural dif-ference with the P-wave section. Unfortunately, there wasno major distinction between the northern pay AB and south-ern wet AB anomaly. Future research should investigateother attributes within the C-wave data and strive for a dis-criminative pay signature.

Just as the two synthetics appeared to be stretched ver-sions of each other, reflector packages on the two line ver-sions could be correlated in the much the same way. Theyappeared much like sections on either side of an expansionfault and were correlated by matching key reflectors withslow, steady dragging of one section across the other. Brine-


a)

b)

Figure 5. (a) Line 2 P-wave section with interpretation. (b) Line 2 C-wave (convertedshear wave) section with interpretation.

filled sand reflections could be seen on both line types, whilethe pay zones typically were seen only on the P-wave dataand not on the C-wave line. Thus, when using both data sets,a negative C-wave to P-wave contrast is one method of high-lighting gas-filled zones.

Line 2. This line, oriented EW across the northern portionof the 141/144 field (Figure 1), extended from the 1998 Hall-Houston SMI 141 5 across the graben faulting to the 1974Forest SMI 142 4 well. The 141 5 was drilled on the sameside of the graben as 144 C-1 but into a separate AB closure.A deeper pay (B-1) level had an untested moderate ampli-tude anomaly that although distorted in time, areally resem-bled a fault-bounded three-way closure. Lastly, there was agas show in the D sand in another offstructure well. Thesecommon prospect elements drove the decision to drill 1415, but it meant another test into an area of severely attenu-ated seismic data.

P-wave data from this line (Figure 5a) and its equivalentextracted from the 3-D volume showed many of the sameartifacts on Line 1. Faults were not clearly imaged in the poordata zone and the water bottom appeared abnormally rugose.There were multiple shallow gas hazards between it and theobvious AB amplitude anomaly at 0.78 s (2260 ft subsea) onthe western side of the graben. There was a series of verysmall AB through B-1 amplitude anomalies on the easternside of the structure updip from the Forest well. The west-ern AB anomaly was similar to that seen on the northernpart of line 1 with a strong trough/peak envelope. Time sagswere observed beneath the shallow gas and at 144 5, the ABwedge had a maximum thickness of 55 ms (two-way time).

There was severe energy loss below the AB until at about

twice its depth when reflector energy progressively beganto regain strength. However, after the E reflection at 2 s, therest of the section lost most of its energy, with only faint hintsof steep dip paralleling a buried salt spire. On the originalspeculative 3-D data, the flanks of the salt were fairly easyto determine but the crest of salt was not imaged at all. Itwas assumed that the cumulative effect of the shallow gaszones had effectively eliminated this usually strong reflec-tor. Because the aperture was intentionally chosen more forthe shallower section, the new P-wave line did not imageany of the salt body. P-wave events on both data sets did notclearly correlate from one side of the structure to the other.

Results from key wells on line 2. Hall Houston 141 5 (wellC in Figure 3) drilled through one of the shallow gas haz-ards at 0.41 s and encountered 20 ft of gas at 1030 ft subsea.The AB top was 2135 ft subsea, which was 190 ft high to adepth-converted 3-D time map, but came in exactly asexpected if the offstructure dip rate had been extrapolatedup into the poor data zone. The sand was 250 ft thick witha 15-ft commercial gas show at the top. Three other mem-bers within the gross sand package showed evidence ofresidual gas. The gas/water contact was higher at this wellthan in 144 C-1, confirming the predrill interpretation thatthe AB had two distinct closures on the same side of thissame trapping fault.

The most interesting results were found below the AB,where the data were severely attenuated. Fifty feet of paywere found at the time-distorted B-1 level. In addition, thenext 15 sands were full of gas, giving a total of 319 ft netgas in this obscured, poor data section. All deeper topscame in high to predrill maps that had already attemptedto correct for some expected time sag. One additional faultwas unexpectedly crossed, suggesting a migration prob-lem within the original 3-D data.

The Forest 142 4 (well D in Figure 3) was outside theshallow gas hazards and found the AB sand wet at 2615ft subsea. It encountered two small shows below AB butno amplitude anomalies were at those depths. The Forestwell is on the eastern flank of the structure and confirmedthe presence of salt at 7155 ft subsea with an excellenttime/depth tie to the 3-D data. No sonic logs or synthet-ics were run in either well on this line. However, becausethe two new seismic lines intersect each other offstructureon the northwest side of the graben, correlation ties werecarried to the western side on line 2. The AB to B-1 sandsin both line 2 wells were easily correlated and given thegood velocity fit; the eastern side of the structure was theninterpreted.

Line 2 C-wave seismic. The continuity and consistency ofevents on C-wave line 2 (Figure 5b) were excellent, withthe overall structure revealed as surprisingly simple. Therewere again small positional changes of the main faultsand evidence of additional breaks. Reflector offsets werecrisper and could be extended deeper in the section, downto the top of salt. The additional fault in 141 5 well ransubparallel with line 2 and, because of the fault’s low-angle nature, was not resolved on this single 2-D line either.The top-of-salt reflector became apparent although thesteeper flanks remained unresolved, not unexpected giventhe acquisition geometry.

Using the correlations from the Line 1 C-wave data,there was an excellent depth structure tie at the westernAB level with no time sag or dip reversals noted. The char-acteristic high-amplitude seismic marker of the “E” sandwas again apparent and provided a good base for the pro-


ductive interval. The new pay sands were interpolatedbetween these two in the same way as on line 1. The shal-low section was easy to match on the eastern side of thegraben by simple jump correlation of reflections and cor-related on the basis of reflection character. There were noamplitude anomalies on the C-wave section and unfortu-nately no significant differences noted among the wet ABin the Forest well, the false DHI in 141 5, or true pay sandsdeeper in the section.

Conclusions. The structural interpretation across the SMI141/144 field was greatly improved using C-wave data.Dip rates and faulting were better imaged and matchedthe subsurface control very well, thereby lowering inter-pretation risks away from subsurface control. There wereslight position and angle changes of the known, majorfaults and evidence for faults not previously mapped.Reflections previously masked and/or distorted by shal-lower gas hazards, including thick gas bearing sands, wererevealed by shooting, processing, and interpreting four-component seismic data. The good regional seismic eventsthat were characteristic markers remained to help tie intothe sections. The ability to jump-tie correlate from one sideof the graben to the other was much easier with the 2-DC-wave data than with speculative 3-D P-wave data set.The signal-to-noise ratio was better although there was alower frequency appearance to the data. It didn’t precludeseeing reflector variations along the section and allowedfor some basic seismic stratigraphic interpretations.

The C-wave data require their own velocity functionto migrate and convert to depth but the 2:1 P-wave to C-wave rule of thumb allowed a fairly close vertical scale

match. The P-wave sonic log and use of Krieff’s equationswere fully adequate to create a good synthetic to tie the C-wave data. A dipole sonic in an uncased well would stillbe the preferred shear-wave source for subsequent syn-thetic or VSP work. Longer-offset cables and larger signalsources should provide deeper penetration and better steepdip imaging. The polarities of the P-wave and C-wavedata sets were processed and displayed to be the same.

In contrast to P-wave data, converted waves do not per-mit direct detection off hydrocarbons. Because shear wavesare unaffected by the type of fluid that fills the pore space,they cannot distinguish areas of hydrocarbons from brineor produce bright spots due to anomalous velocity changes.The combination of P-wave amplitudes overlain onto moreprecise C-wave structures is the way to best utilize bothdata sets. Additional work on C-wave AVO and cross-plotting techniques show promise in regaining the dis-criminating edge lost from having no amplitude anomaliesto highlight likely pay volumes.

Gas chimneys are common in certain parts of the Gulfof Mexico and may be obscuring untested hydrocarbon accu-mulations. This paper has illustrated the benefits of usingfour-component data in a gas cloud using 2-D test lines. Thisnew seismic technique is still early in its evolution but showsgreat promise. With additional experience and decreasingcosts, it may contribute to another significant increase inexploration and development success ratios throughout theGulf of Mexico in the same way as P-wave bright spots and3-D seismic have already done. LE

Corresponding author: T. Englehart, [email protected]; A.Bertagne, [email protected]


interpretation of four-component seismic data in a gas

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