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The Paleogene of the Gulf of Mexico and Caribbean Basins: Processes, Events, and Petroleum Systems 398

Session I Session II Session III Session IV Session V Session VI Session VII Session VIII

Exploration and Appraisal Challenges in the Gulf of Mexico Deep-Water Wilcox: Part 1—Exploration Overview, Reservoir Quality, and Seismic Imaging

Lewis, JenniferClinch, SimonMeyer, DaveRichards, MattSkirius, ChristineStokes, RonZarra, Larry

Chevron North America Exploration and Production Company

1500 Louisiana StreetHouston, Texas [email protected]

Abstract

The deep-water Wilcox trend covers more than

34,000 mi2, extending across the Alaminos Canyon,Keathley Canyon, and Walker Ridge protraction areas,plus parts of adjacent protraction areas and Mexicanterritorial waters. Discoveries are in turbidite sands thathave been deposited in lower slope channels and pon-ded fans to regionally extensive basin floor fan systems.Primary trap styles are compressional Louann salt-cored symmetrical box folds, symmetrical salt pillows,and asymmetrical salt cored thrust anticlines. More than20 wildcat wells have been drilled in the Wilcox Trend.Recoverable reserves for each of the 12 announced dis-coveries range from 40 to 500 million barrels of oil

(MMBO). Ultimately, the Wilcox trend has the poten-tial for recovering 3 to 15 billion barrels of oil reserves(BBO) from these discoveries and additional untestedstructures. Many technical issues need to be resolved tomove the billions of barrels of resources trapped indeep-water Wilcox structures to recoverable economicreserves. Exploration challenges include well depths upto 35,000 feet subsea, water depths ranging from 4,000to 10,000 feet, and salt canopies from 7,000 to morethan 20,000 feet thick. Allochthonous salt covers 90%of the trend, complicating regional reconstructions andresolution of individual structures. Appraisal challengesinclude: delineating and modeling reservoir quality,

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sand distribution, and flow capability; improving com-plex sub-salt images; and developing cost effective

drilling, completion, facility, and infrastructure designs.

Introduction

The Wilcox Formation is an important petroleumtrend in the northwestern Gulf of Mexico coastal plain.Earliest production was established in south and south-east Texas in the late 1920’s. Continued explorationdelineated fluvial, deltaic, and shallow marine sand-stone reservoirs ranging from the Burgos Basin innortheast Mexico to Texas, Louisiana, Mississippi, andAlabama. Estimated recoverable reserves (EUR) fromthe onshore Wilcox trend exceed 30 trillion cubic feet

(TCF) of gas. Most of the onshore reserves are gas, andmost have already been produced.

Recent discoveries in the deep-water Gulf ofMexico document a significant petroleum resource inturbidite channel and fan systems that are deep basinequivalents to the onshore Wilcox trend. These deep-water Wilcox turbidite reservoirs are located more than250 miles downdip from delta systems in the onshoreWilcox subsurface section, and extend for more than300 miles across the deep basin (Fig. 1).

Objectives

The purpose of this two-part paper is to reviewthe critical obstacles and challenges that must be over-come in order for the deep-water Wilcox trend to movefrom a highly successful exploration play to a profitableproducing trend. In Part 1, we review some of theexploration challenges associated with exploring in a

high cost and high risk environment. We also discusssubsalt seismic imaging and reservoir quality.

Part 2 is primarily focused on uncertainties rele-vant to permeability. We also address permeabilitymeasurement and transforms, modeling, and factorsthat affect local permeability distribution.

Exploration challenges

Some of the challenges involved in exploring thedeep-water Wilcox trend are a result of geographiclocation in the basin. The trend extends across Alami-nos Canyon, Keathley Canyon, and Walker Ridge, plus

parts of adjacent protraction areas (Fig. 1). The range ofwater depths for the trend is from approximately 4,000to 10,000 feet. The top of the Wilcox is as shallow as12,000 feet in the Perdido Fold Belt area of Alaminos

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Canyon, and ranges to more than 30,000 feet subsea ontrend to the east. About 90 percent of this trend islocated under modern allocthonous salt canopies, whichrange from 7,000 to more 20,000 feet thick.

Exploring at these depths for objectives below athick salt canopy involves complex drilling programsusing high-cost rigs, which are limited in number andavailability. Another complication of exploration in thesubsalt environment has been generally poor seismicresolution in conventional 3D seismic surveys. Recentseismic wide-azimuth (WAz) towed streamer acquisi-tion and processing has greatly enhanced the ability toconfidently map the subsalt environment (Lewis andNeal, 2007). However, individual sandstone reservoirsremain below seismic resolution.

Exploration results to date indicate that the prob-ability of finding sandstone reservoirs in the deep-waterWilcox section is high, as all of the exploration andappraisal wells in this trend have encountered some tur-bidite sandstones. This depositional system traversesapproximately 400 miles, from Alaminos Canyon in thewest, to Atwater Valley in the east (Fig. 2). Integratedwell and seismic interpretations define a turbidite suc-cession up to 6,000 feet thick in Alaminos Canyon, andabout 2,500 feet thick in eastern Walker Ridge. Strati-graphic analysis of more than 20 wells across this trenddocuments a regionally extensive series of turbidite sys-tems. Depositional settings for these turbidites rangefrom leveed channels, ponded fans, and channelizedfans in Alaminos Canyon, to channelized and uncon-

fined fan systems in Walker Ridge. Stratigraphy anddepositional systems of the deep-water Wilcox trendare discussed in detail in a separate paper at this confer-ence (Zarra, 2007).

The first significant deep-water Wilcox penetra-tion was the Baha well, drilled in 2001 in AlaminosCanyon Block 557. Although this well was a dry hole, itdid find 4,500 feet of Wilcox turbidites containing a 12foot oil zone (Fig. 3). The Baha #2 well was soon fol-lowed by discoveries at Trident (Alaminos CanyonBlock 903) in late 2001 and Great White (AlaminosCanyon Block 857) in 2002. In late 2002 and 2003, theWilcox trend was extended more than 250 miles to theeast with the Cascade (Walker Ridge Block 206), Chi-nook Deep (Walker Ridge Block 469), and St. Malo(Walker Ridge Block 678) discoveries in Walker Ridge(Fig. 4). The emergence and development of the deep-water Wilcox trend was reviewed in detail by Meyer etal. (2005) and Meyer et al. (2007).

The only production test in the trend has been atthe Jack #2 well (Walker Ridge 758). The Jack welllocation is in 7,000 feet of water, and the tested intervalis greater than 25,000 feet subsea. In September 2006,Chevron announced a sustained flow rate of over 6,000barrels of oil per day from approximately 40% of thereservoir. Test results significantly increase the under-standing of trend deliverability (Rains et al., 2007).

The first phase of discovery in the prolific deep-water Wilcox trend began in March 2001 with the plug-ging of the BAHA #2 well and concluded in September

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2006 with the press release of the Jack #2 flow-test.During this 5 ½ year period, seventeen wildcats resultedin twelve discoveries that found over 15 billion barrelsof oil in place (Fig. 1). The deep-water Wilcox trendexploration success rate of 70% is two times greaterthan the 35% success rate for the entire deep-water Gulfof Mexico. Approximately 2 billion barrels of oil equiv-alent (BBOE) of resource have been discovered inWilcox turbidites, accounting for 14% of the 16 BBOEtotal resource discovered to date in all deep-water Gulfof Mexico trends. Over $2 billion have been spent todrill, delineate, and test relatively well imaged salt-cored anticline structures that lay either outboard of theSigsbee Escarpment (Fig. 4A) or just within the sub-salt environment at the distal edge of the Sigsbee Can-opy system (Fig. 4B). This high-cost, high-potential,deep-water Wilcox trend has a potential ultimatereserve range of 3 to 15 BBOE with a mean of 8 BBOEreserves (Meyer et al., 2005).

The next generation of exploration and drillingwas initiated by the 2006 Kaskida discovery in KeathleyCanyon Block 292. This was the first Wilcox sub-saltwildcat located significantly inboard of the SigsbeeEscarpment and penetrated a much more complex seis-mic imaging area (Fig. 5). Complexities in this northerntier of Wilcox prospects included a more dynamic salttectonic history, which influenced both depositional anddiagenetic components of the Wilcox petroleum system.

Prospective structures are typically juxtaposedagainst salt roots or welds resulting in 3-way dip-com-ponent trap closures. Approximately 70% of the deep-water Wilcox Trend lies within this structural province,a factor that has influenced the next generation of seis-mic acquisition and processing. The success of this newtechnology will play a major factor in unlocking thepotential of the Wilcox in this area.

Seismic imaging challengesAs industry progresses into appraisal and develop-

ment of deep-water subsalt fields, answers to new andincreasingly detailed questions are sought in an effort tominimize risk and optimize project value. However,with only a handful of well penetrations and generallypoor quality subsalt seismic data, many structural uncer-tainties remain. Key uncertainties such as faulting,compartmentalization, and overall structural geometryall play prominent roles in determining well placement

and well count, factors that impact ultimate recovery,development scenarios, and project economics.

The seismic data quality covering this frontierarea is typical of many subsalt images. Data at the res-ervoir level are low frequency (~10 Hz dominant) andcontaminated with remnant multiple noise, makingcharacterization of key reservoir uncertainties such asfaulting an onerous undertaking at best. Amplitudeanalysis of the reservoir is inappropriate given the mod-

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est angle of incidence (mid-20° range), weak anduneven subsalt illumination, and the lack of a fluidresponse in consolidated, grain-supported rocks.

Much of the structural uncertainty on maps inter-preted from subsalt pre-stack depth migrated data(PSDM) can be attributed to poor vertical resolutionand velocity error. Velocities in the initial vendor specu-lative PSDM analyses do not resolve a regional low-velocity layer nor incorporate anisotropy in the modelthat results in a seismic image which is, in general, toodeep and steep. Furthermore, the salt model lacks detailin key areas which also degrades the subsalt image.Subsequent products incorporate more detail in theirsediment velocities and salt models, but with few wells,subsalt velocity resolution is limited by geometry of thesalt canopy, which allows a subsalt angle of incidenceof no more than 25°.

Seismic resolution issues are compounded by alow signal-to-noise ratio. Over many structures in thisregion, the water bottom and top salt are separated by athin sheath of sediment while the reservoirs are beneathan undulating salt layer that can exceed 10,000 feetthick. The challenging result of this configuration isthat water bottom and top salt multiples commonlycoincide with and contaminate primary energy at thereservoir level. A representative example of the effectof top salt and water bottom multiples on seismic qual-ity is shown for a seismic transect at the Jack field(Fig. 6).

To date, all PSDM products covering subsalt Wil-cox fields show acoustic artifacts resulting fromattempts at multiple attenuation. In some products, theremnant multiples overwhelm the primary events. Inothers, the multiples are removed but at the expense ofoften severe primary attenuation. Perhaps most distress-ing is that when remnant multiples are migrated, “wave-fronted” noise trains combine with primary events, andmay resemble the geometry of a faulted anticline, whichis a reasonable geologic scenario. Needless to say, givenfew wells and a weak seismic image, characterization ofthe structure, much less the reservoir, presents a consid-erable challenge. Our basic assertion is that in a deep-water, sparse well setting, better seismic data qualityleads to better decisions. Hence, we should do every-thing possible to improve the quality of seismic data.

Recently, industry has recognized a step-changeimprovement in subsurface imaging in deep-water sub-salt settings with wide-azimuth (WAz) towed streameracquisition and processing. Presented with the opportu-nity for a similar improvement in the data quality over aChevron-operated field, an integrated modeling effortwas undertaken to understand the best approach toenhance signal-to-noise through new seismic acquisi-tion (Lewis and Neal, 2007). Results suggest that WAzuplift is primarily due to inherent multiple suppression,and to a much lesser extent, enhanced illumination andincreased fold. Upfront multiple attenuation throughacquisition offset allows for gentler parameterization ofdemultiple algorithms, leaving more opportunity to pre-

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serve the integrity of primary energy. Early dataanalysis indicates that the WAz survey contributes to ahigher quality subsalt image, facilitating a clearerunderstanding of structure, faulting, and perhaps

stratigraphy. Increased confidence in interpretation canlead to improved characterization of risk and uncer-tainty throughout the entire appraisal process.

Reservoir quality challenges

Understanding the factors affecting porosity andpermeability is paramount for reservoir modeling in theappraisal and development stages of project maturation.The reservoir sections at the Jack and St. Malo struc-tures are very thick, consisting of approximately 1,400to 1,600 feet of turbidite deposits within moderatelyhigh energy, basin floor distributary fan to channelizedfan systems. The gross depositional facies described forthe Wilcox 1 (upper unit) and Wilcox 2 (lower unit) areremarkably consistent across a large portion of WalkerRidge, showing similar depositional characteristics overthis large area. Coring to-date of the reservoir intervalson these structures (917 ft. total of conventional core)still only samples less than 20% to 30% of the potentialreservoir section, and there is more extensive core cov-erage for the Wilcox 1. The core samples, however,form the basis of our understanding of reservoir qualityand are used to link petrologic analyses to depositionalfacies. Also, the conventional core data are calibrated tothe electric log responses so that the logs can be used tomore accurately predict reservoir quality over intervalswith no core control. Calibrated logs are employed topopulate reservoir characteristics in static and dynamic

reservoir models from which all economic and produc-tion forecasts are based.

One of the key technical challenges for commer-ciality of the Wilcox trend is reservoir quality and howit relates to flow capability. Wilcox reservoir rocks aregenerally characterized by low permeability, with mea-sured core permeability typically less than 10millidarcys (md). Measured core porosity values rangefrom approximately 15% to 25%, but within this poros-ity range, permeability can vary over three orders ofmagnitude. The large range in permeability data pro-vides a difficult challenge for accurate permeabilitymodeling, where this range must be reduced to less thanan order of magnitude. To achieve this goal, we havegenerated electrofacies to group rocks with similar fluidflow properties. By adopting fluid flow-based electrofa-cies at Jack and St. Malo, the range in permeability atany given porosity has been reduced by half. Outsidecore control, the use of a single transform has the poten-tial to introduce large biases. To reduce the possibilityof this potential bias, it is important to implement multi-ple permeability transforms from various data sourcesand compute the average of all transforms.

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Although low permeabilities are characteristic,measurements up to ~200 md have been documentedwithin certain intervals. Measured core permeabilitiesare generally higher in the deeper Wilcox 2 comparedto the Wilcox 1. In addition, the highest permeabilitiesare not always associated with the highest porosities.The controls on permeability are found to be a complexinterplay of depositional facies, compaction, anddiagenesis. The ability to accurately predict porosityand permeability at the prospect and regional scales willdetermine our success at development well placementand play longevity.

Typical Wilcox reservoir rock is described asvery fine-grained, lithic-rich, thinly interbedded to mas-sive sandstone. However, differences in sandstonedepositional facies, texture, and grain composition areobserved within the Wilcox 1 and Wilcox 2 that have animpact on reservoir quality. The Wilcox 1 representsunconfined deposition within the inner, middle, andouter portions of a distributary fan system. In contrast,the Wilcox 2 represents deposition within a channelizedfan system. Highest measured permeabilities are associ-ated with some better sorted, relatively coarser-grained,planar laminated to graded tractional deposits associ-ated with a channel axis lithofacies association. Forboth the Wilcox 1 and the Wilcox 2, grain sizes arecharacteristically very fine; average grain sizes rangefrom coarse silt to fine sand, and sorting is generallymoderate to poor. In general, better permeability corre-lates to better sorting and lower clay content. Grain size

shows no correlation to permeability except for thewell-sorted tractional (Tt) deposits of the channelizedfacies. Except for these tractional (Tt) deposits, deposi-tional facies are not easily characterized by grain size orsorting. Overall, textural attributes are first order depo-sitional controls on reservoir quality and permeabilityfor the Wilcox.

In addition to very fine grain size, Wilcox reser-voir rocks are also characterized by high lithic graincontent. Sandstones are classified as feldspathic lith-arenites and show a distinctive trend to more quartzgrain-rich compositions in the Wilcox 2 (Fig. 7). Thegenerally more quartz-rich grain composition of theWilcox 2, along with slightly coarser grain sizes andbetter sorting, likely reflects the increased energy of achannelized depositional setting. Lithic grain types inboth the Wilcox 1 and Wilcox 2 are generally similar,the most abundant being finely crystalline, schistosemetamorphics. Other important grain types are variablyaltered silicic volcanics and sedimentary rock frag-ments such as shale, and mica grains (muscovite andbiotite). Although the proportions of volcanic (VRF),metamorphic (MRF), and sedimentary (SRF) rockfragment grain types are generally similar for the Wil-cox 1 and 2 (Fig. 7), depth trends of some grain typesand slightly shifting lithic grain type abundancebetween wells may indicate slight changes in the sourceof sediment input over time. Depth trends in clay typesare also apparent in the data, reflecting changing detri-tal mineralogy as well as a diagenetic overprint.

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Diagenetic effects are assessed in terms of com-paction and cementation. Compaction due to effectivestress has a greater effect on Wilcox 1 sandstone due toits higher content of ductile grain types, particularlyaltered volcanic and micaceous metamorphic lithictypes. The Wilcox 2 sandstone is richer in rigid quartzgrains, and as such, is less prone to porosity loss fromcompaction (Fig. 8). In addition, because of the higherabundance of micaceous metamorphic lithics and micagrains in the Wilcox 1, grain shapes tend to be elongatecompared to the more equant-shaped quartz grainscommon in Wilcox 2. This difference in grain shapeaffects grain packing arrangement at deposition thatwill subsequently influence pore size and pore geome-try with continued compaction and cementation.

In addition to the effects of compaction, cementa-tion also plays a role in Wilcox reservoir quality.Cementation is dominantly controlled by temperatureand occurs primarily as quartz overgrowths on detritalquartz grains. Other cements include authigenic clays,

particularly chlorite grain coatings, and carbonate min-erals. Chlorite clay is observed in the highestpermeability samples as nearly complete grain coatingsthat inhibit quartz cementation. Quartz cement is moreabundant, on average, in Wilcox 2 compared to Wilcox1 because more quartz grains are present as nucleationsites and also because deeper and hotter conditions aremore conducive to cementation. However, the presenceof minor to moderate amounts of quartz cement doesnot necessarily detract from the overall reservoir qualityof higher permeability samples in Wilcox 2.

Touchstone diagenetic modeling is being appliedto the Jack and St. Malo assets to yield porosity andpermeability predictions for current and futureappraisal well locations based on 2D and 3D geohistorymodels. Model results, based on analogs calibrated toconventional core, depositional facies and electrofacies,should guide our interpretations of permeability distri-bution across these large structures.

Conclusions

Since 2001, more than two dozen wells have beendrilled into the deep-water Wilcox. While geologic suc-cess rates are very high, economic viability for somediscoveries remains uncertain. Complex reservoirrocks, complicated geohistories, and low permeabili-ties, require a significant focus on reservoir quality and

basin histories. Water depth, reservoir depth, and poorseismic imaging provide added complications. Solu-tions in progress include: WAz seismic surveys,petrologic work on whole core, detailed formation eval-uation of logs, basin modeling, and diageneticmodeling.

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References

Lewis, J., and S. Neal, S, 2007, Wide -azimuth seismic at thesubsalt Jack asset: Is it worth the early investment?:The Leading Edge, v. 26, no. 9, in press.

Meyer, D., L. Zarra, D.B. Rains, R. Meltz, and T. Hall, 2005,Emergence of the Lower Tertiary Wilcox trend: WorldOil, v. 226, no. 5, p. 72–77.

Meyer, D., L. Zarra, and J. Yun, 2007, From BAHA to Jack,Development of the Lower Tertiary Wilcox Trend inthe Deep-water Gulf of Mexico: Sedimentary Record,v. 5, no. 3, in press.

Rains, D. B., L. Zarra, D. Meyer, 2007, The lower TertiaryWilcox trend in the deep-water Gulf of Mexico:

AAPG National Convention, Long Beach, California,

29 p. http://www.conferencearchives.com/aapg2007/

sessions/player.html?sid=07041202 (last accessed

September 5, 2007).

Zarra, L., 2007, Chronostratigraphic Framework for the Wil-

cox Formation (Upper Paleocene–Lower Eocene) in

the Deep-Water Gulf of Mexico: Biostratigraphy,

Sequences, and Depositional Systems: GCSSEPM

Foundation 27th Annual Bob F. Perkins Research

Conference, in press.

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Figure 1. Deep water Gulf of Mexico trend map showing relevant wells and possible areal extent of the Wilcox turbid-ite trend. Summary of wildcat wells is tabulated from press releases and interpreted from publicly available data (as ofJuly, 2007). Locations for seismic lines shown on Figures 2 through 6 are also indicated on this map.

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Figure 2. Regional 2D time seismic transect and interpreted cross section extend ~425 miles, from the Perdido Fold Belt to the Mississippi Fan Fold Belt, outboardof the modern allocthonous salt canopy. On this section the Wilcox is an essentially tabular unit, thinning from west to east.

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Figure 3. The Baha #2 well was located on a thrusted, symmetrical box fold in the Perdido Fold Belt area of AlaminosCanyon. This 2001 wildcat was the first significant penetration of deep-water Wilcox turbidites and documented aworking petroleum system.

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Figure 4. (A) The 2002 Cascade wildcat was drilled on a well imaged salt cored anticline outboard of the modern allocthonous salt canopy. This was the first Wil-cox discovery in Walker Ridge. (B) The 2003 St Malo wildcat was drilled on a salt cored anticline and was the first subsalt discovery in the deep-water Wilcoxtrend.

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Figure 5. The 2006 Kaskida discovery in Keathley Canyon Block 292 was the first Wilcox subsalt wildcat located signif-icantly inboard of the Sigsbee Escarpment. This well penetrated a more complex seismic imaging area than wells closerto the outboard edge of the salt canopy.

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Figure 6. At Jack, three significant free-surface multiples associated with water bottom (wb) and top salt (ts) mapdirectly to the reservoir level. The structure is relatively well illuminated for the subsalt but multiples coincide with andcontaminate the reservoir signal, imposing a significant challenge in reservoir imaging.Copyright © 2007

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Figure 7. Normalized Quartz (Q), Feldspar (F), and Lithic (L) sandstone compositions for Wilcox 1 (upper unit) andWilcox 2 (lower unit). Ternary plot in upper right shows normalized total volcanic (VRF), metamorphic (MRF), andsedimentary (SRF) lithic compositions for the Wilcox 1 and 2.

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Figure 8. Representative photomicrographs of Wilcox 1 (left) and Wilcox 2 (right) sandstone taken at the same magni-fication (100X). These photos illustrate the general change in reservoir sandstone grain composition and texturebetween the lithic-rich Wilcox 1 and the more quartz grain-rich and slightly coarser-grained Wilcox 2.

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lewis, jennifer clinch, simon meyer, dave richards, …exploration and appraisal challenges in the...

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