ST-26 and East Bay (SP-24/27) Fields.

D3D-imp Anomalies vs Known (current) Pay

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Early in 2002, a “Special Project” was launched to show how, after three inconclusive-to-management years, the D3DSP could be used to find petroleum and make money for a licensing company. This Figure DvC2-00 shows the compiled results from the first phase of the three-phase, proof-of-concept Special Project

(Phase 1) Compare known pay (or no pay or no reservoir) zones with anomalous (or non-anomalous) D3D-impedance at appropriate two-way-times, corresponding to logged perforations or drilling target depths.  {Result:  This scoreboard shows these positive but admittedly "limited" results.}

The other two phases of the 2002 proof-of-concept Special Project were:

(Phase 2) [Try to] Get a D3D-recommended test well approved at either ST-26 or SP-24/27. {Result: None of the eighty [80] leads and seven [7] recommended wells were drilled, because the unconventional D3DSP was unable to attract management or geo-engineering support}.

(Phase 3) D3D-reprocess and volumetrically analyze a (conventionally risky) prospect that had been identified and leased, and was actively seeking a drilling partner. Phase 3 has become the   EI-27 CIB CARST sand success story, told in the captions to the following slides.

But this "Special Project" (Phase 1) scoreboard presentation strongly supported, in mid 2002, the use of the D3DSP to reduce drilling risk and increase per-well recoveries. The display is actually six scoreboards, each showing comparison events that either

    • Supported D3D (shown as "D3D", the “visitor”, on the top row), or
    • Condemned D3D (hence, the "No D3D", the conventional “home team”, on the bottom).

At each zone studied in each well, a judgment was made as to the economic commerciality of the production and the “strength” of the D3D anomaly, which almost always turned out to be low D3D-impedance, in these Tertiary clastic sandstone reservoirs on the Gulf of Mexico shelf. The choice of "good well" or "poor well" was based on the answer to the question:  "If we knew before drilling, that this production or logged zone was what we would find, would we still have drilled and completed this well, in this zone?"  Answering, "No", to this question meant it was a "poor well". Answering, "Yes", meant it was a "good well".  Obviously there are many marginal wells that have been drilled and completed, that turned out to be unprofitable for the operator and investors. For this scoreboard, these would be classified as "poor wells".  Here, the "good vs. poor" judgments were based on cumulative production, estimated ultimate recoveries, and (for some very poor wells) an uncompletable P&A status for the zone. Drilling and completion costs were not considered.

Seismically, an "unequivocal" D3D-impedance anomaly (or non-anomaly) was one that was not near the edge of a survey and for which confidence existed about the correct (two-way-time) TWT-depth relationship that matched its TWT position to the logged target depth. It is remarkable, that low-D3D-impedance anomalies (uncommonly low values) were found in all of the anomalous cases, whereas non-anomalous responses never registered very high or very low D3D-impedance.  For the 26 D3D-impedance anomalies where the logged production (or barren zone) wells were also "Unequivocal" (see above) there was no disagreement about the status of the D3D-impedance anomalies, by any geologist or geophysicist. Thus, there were two categories (good and poor) for both well zone production results, and D3D-impedance-anomaly results.

Two possible categories for two data types yielded four possible combinations for the "Logged Pay versus D3D-impedance" comparisons. The two comparison results that strongly support the use of the D3DSP are:

    • A good low-D3D-impedance anomaly, correlating with a highly commercial productive perforated zone, which would lead to many possibly over-looked drill sites, and higher reserves per well, or
    • A poor or absent D3D anomaly, correlating with a dry hole or marginally commercial perforated zone, which would lead to fewer dry or marginal wells drilled, and would also lead to higher reserves per well in a drilling program.

The other two comparison results that condemn the use of the D3DSP are:

    • A good low-D3D-impedance anomaly, correlating with a dry hole or marginally commercial perforated zone, which would result in wasted D3D-drilling dollars, or
    • A poor or absent D3D anomaly, correlating with a highly commercial productive perforated zone, which would result in many missed, profitable opportunities.

The left side of Figure DvC2-00 shows the result when the above comparisons were tallied using only the thirty-two wells that had unequivocal (unquestioned)

    • Correlations (everyone believed the seismic-to-well-depth correlation),
    • Production results (either a definite money-maker or a definite disappointment),
    • Seismic data “quality” (in the sense that the well was not near the edge of the D3D volume, or under a severe skip, etc.), and
    • Anomaly Quality (either very strong or essentially absent, but not questionable).

The score was 14-0 in favor of D3D at ST-26, and 18-0 in favor of D3D at EPL’s East Bay field in the South Pass OCS area.

The right side of Figure DvC2-00, shows the result when all "Questionable" comparisons were included in the tally: the score was still 16-4 at ST-26 and 41-15 at East Bay.

{Incidentally, the East Bay D3D-reprocessing project was the second EPL attempt to evaluate the usefulness of its D3DSP license.  But at this mature, Shell-discovered, billion-barrel oil and gas field at the mouth of the Mississippi River, the complex near-surface velocities and the low stack-fold (produced by the multiple source-type shooting to avoid production facilities) frequently made both the depth-to-time conversion of the log curves and directional well paths, problematic and also lent suspicion to the travel-times and dip rates on the post-stack migrated [D3D and non-D3D] seismic data. That is why there are many more questionable comparisons for East Bay than ST-26.}

In Figure DvC2-00, the upper ("Game 1”) scoreboard panel represents "D3D versus Logged Pay" comparisons at ST-26, and the middle, ("Game 2”) panel is for East Bay. In the lower ("5/31/02") panel final analysis, 76 zones in 73 wells were compared with 76 D3D-impedance in-line/cross-line pairs.  In all, the use of the D3DSP to discover or develop reserves known to be un-drained when the respective seismic data were recorded (and its use to avoid drilling into non-commercial zones), was supported by the combined Questionable-plus-Unequivocal score of 57-19 (73% for D3D). The score was 32-0 (100%) when all questionable scenarios were excluded. A few of these logged-pay-versus-D3D-impedance "Anomaly Strength” comparisons at ST-26, are shown in Figures DvC1-00, -05, -10, -11, -12, and -13, but this complete study has not yet been published.

At about the same time, also supporting the quantitative and qualitative value of a D3D-impedance volume, was the welcome and unexpected poster paper written by Dr. Vitor Abreu, an ExxonMobil geologist (formerly employed by an EPL partner, at ST-26), and later co-authored by other geo-engineering personnel, including the author.  This AAPG-award winning paper showed, among numerous other geological conclusions, that the reprocessed D3D-impedance traces not only contained low-D3D-impedance “anomalies” that correlated well with known pay (per the scoreboard, above), but also provided a better fit to known depositional environment log curve-shapes (deltaic and fluvial sands, both wet and hydrocarbon-bearing) than more conventionally processed data sets. The other two seismic volumes used in his comparison were the original (un-reprocessed) volume, containing DMO, post-stack-migration (with and without trace-integration-to-impedance), and a partner-reprocessed conventional volume using the D3D-deconvolved pre-stack volume, but applying DMO and migrating with a smoothed stacking-velocity field.

 In summary, Phase 1 worked exceptionally well, but was considered to be a limited-use "science project".  Phase 2 failed to get a well drilled and was considered to be "unsuccessful".  And the Phase 3 technical work at Eugene Island Block 27, turned out to be remarkably predictive.  It is discussed in some detail in the captions to the Figures that follow. All in all, these poster paper conclusions and the limited study "scoreboard" make excellent D3DSP-technical stories, but they are only the preface to the EI-27 (re-) discovery story, told in the Figure captions that follow.

 It will become obvious that the D3D-reprocessing and volumetric analyses did not "generate" the EI-27 prospect.  But this 3rd phase of the proof-of-concept, was never intended to be a "prospect generation" phase. That was the task of Phase 2, which was definitely "unsuccessful" at getting any D3D-generated leads drilled. Nor was the eventual choice of the EI-27 exploratory drill site based (solely) on a D3DSP recommendation. But the D3DSP analyses strongly supported the (only slightly too far down-dip?) location, and the EI-27 drill site that was finally approved by management and drilled, remained conventionally risky and, therefore, was unsuccessful at attracting a partner.  Conventionally processed and interpreted exhibits were presented to potential partners for many months, prior to the start of the D3DSP analysis.

The EI-27 EPL #1 exploratory test site did test many D3DSP predictions, including:

 Prospectivity - The D3DSP analysis predicted uncommonly profitable success, and led to an informal, very strong recommendation to drill it 100% ... with no partner. The D3DSP analyses were only mentioned, briefly, to one potential partner - who still declined.

 Reservoir gas sand thickness - The EPL #1 well came in slightly thicker than the 35-feet predicted, because of the faster than expected velocities (based on the Norcen #2 logged 10,000 f/s gas sand]. It found, as predicted, the center of the submarine channel shown on the D3D-impedance "amplitude map"; with black 20 ms (~80 feet) structural contours overlain (Figure DvC2-06).

 Gas, rather than oil or "fizz water" - This result was predicted due to the very low sample  (VOXEL) values within the interpreted CIB CARST sand D3D-impedance "trough". The well-cemented sands were faster than expected (very nearly as fast as the encasing shales) but the density was quite low, producing the low-D3D-impedance seismic anomaly.  At the time, one of the most risky scenarios was that this was a water-swept gas reservoir "footprint".  But because the D3D-processing sequence attempts to produce an OVA (offset variations absent, by muting out anomalous far-traces) volume, and because fizz water elastic properties can produce various AVO (amplitude variations with offset) effects, the very low D3D-impedance samples (or VOXELs) at the CIB CARST level strongly suggested the #1 well would find a low-impedance (Density * Velocity) gas sand. D3D-impedance traces are, thus, not much influenced by changes in elastic AVO properties of the rock formation. And it predicted correctly.  Fizz-water densities will always be higher than producible gas densities, in an identical reservoir matrix, even though conventional amplitude anomalies are sometimes seen over fizz-water-filled sands. Experience with D3D-impedance data in such areas suggests that many of these conventional fizz-water anomalies vanish when AVO effects are eliminated from the stacked traces (mostly due to the more severe initial-muting used).

 Recoverable volumes - Based on the 26+ bcfg Norcen #2 production to the south, the D3DSP gave this low-D3D-impedance CIO much more recoverable gas than the 8.2 bcfge produced by the Odeco #4 well (up-time-dip, to the west), before "watering out".  In fact, the D3DSP did choose an alternate location (up-dip in the same interpreted channel), but the D3DSP analysis at the conventionally selected site, agreed that it would initially be equally successful, just 20-feet farther down-dip than the D3DSP-recommended location. As mentioned above, a strong D3DSP recommendation was made (informally to management) prior to the drilling of this highly successful well ... without a partner. And this strong recommendation probably contributed to a project-engineering decision to install the higher capacity production facilities that turned out to be very profitable in late 2003.

 The predicted gas-water contact, seen on Figures DvC2-06 and -09, was not observed in the EPL #1 well, and the CIB CARST reservoir has been producing (water-free) as if it were a pressure-depletion drive, rather than a water-drive, reservoir. Without further drilling (and logging) data this apparently immovable contact is either:

 a)  Not there, and the sand is full of gas to its base, or

 b)  Present, but diagenetically cemented over the millions of years that it has been in place, or

 c)  Present, but shielded from the producing perforations by low permeability baffles within the reservoir. If this is the case, only time will tell ... but the water that hit the up-dip Odeco #4 well has not yet found its way to the EPL #1 perforations.

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