man detal

New Understanding of the Petroleum Systems of Continental Margins of the World 1

21st Century AtlantisIncremental Knowledge from a Staged-Approach to Development, Illustrated by a Complex Deep-Water Field

Mander, JoannadAblaing, JulieHowie, JohnWells, KenRamazanova, RahilaShepherd, DavidLee, CherieBP America501 Westlake Park BoulevardHouston, Texas 77079, USA

AbstractAtlantis Field represents a significant develop-

ment for BP and co-owner BHP Billiton in the southernGreen Canyon area of the Gulf of Mexico. With pri-mary development from three middle Miocene sands, itis one of BPs largest fields in the deep water Gulf ofMexico.

Discovered in 1998 and first production in 2007,Atlantis Field was developed in stages from a sub-seadrill center to a remote production facility. A secondsubsea drill center, centered on an early appraisal well,was connected in mid 2009. Drilling of water injection

wells commenced in 2009 following initial dynamicdata learning. Additional field development viaappraisal drilling is planned for 2012, and two dynami-cally positioned semisubmersible rigs are currentlyactive in the field.

Located approximately 120 miles (190 km) southof Fourchon, Louisiana, Atlantis Field is a faulted,elongate asymmetric doubly-plunging anticline withinthe Atwater Fold Belt. Water depths range from 4500 to7000 feet (1370 to 2070 m) across the field, influencedby the Sigsbee Escarpment, a region of steep sea floor

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dip created by a thick allochthonous salt complex thatpartially overlies the structure. Both the allochthonoussalt and the significant sea floor relief create challengesin seismic imaging, field development, and have influ-enced the staged approach.

The producing reservoirs are middle Miocenedeep-water turbidites interpreted as a series of individ-ual lobes in a submarine fan complex that weredeposited in a relatively unconfined basin floor envi-ronment. Deformation of the reservoir commencedshortly after deposition and is dominated by the forma-

tion of the Atwater Fold Belt and culminated with thelater partial burial of the structure by the thick alloch-thonous salt canopy. The reservoir was interpreted to becompartmentalized, based on the seismically definedfaults, and these compartments were confirmed bystatic pressures. However, production data now indicatea greater reservoir compartmentalization beyond thatinitially defined. Data acquisition in new wells is tar-geted to understand further the reservoir deformationand stratigraphic complexity that negatively impactspermeability, acting as barriers or baffles to fluid flow.

Introduction Discovered in 1998, Atlantis Field is located in

the southern Green Canyon (GC) protraction area of theGulf of Mexico, about 180 miles (290 kilometers) duesouth of New Orleans, Louisiana (Fig. 1). Atlantis issituated beneath the Sigsbee Escarpment, a majorbathymetric feature associated with the edge of alloch-thonous salt. Complex sea-floor topography plungesfrom 4,500 ft to 7,000 ft (1370 to 2070 m) water depthat slopes up to 30.

Located in the western Atwater Fold Belt, Atlan-tis Field comprises one of a series of northeast-southwest trending anticlines in the southern GreenCanyon area of the Gulf of Mexico, along with Nep-tune, Frampton, and Green Knoll (Fig. 2). The regionalstructure is dominated by northeast-southwest trendinglinear ridges and northeast-southwest trending saltstructures. The linear ridges are salt-cored folds that are

parallel to the shelf edge and have formed by downdipmotion of the Miocene section on top of the mobileJurassic salt.

The field covers five lease blocks, GC 699, GC700, GC 742, GC 743, and GC 744, held by a unitagreement approved in April, 2005. BP is the fieldoperator, having a 56% working interest; BHP Billitonis co-owner, having a 44% working interest. Nearbyfields on production include the BP-operated HolsteinField located about 32 miles (50 kilometers) to thenorthwest and the BP-operated Mad Dog field (discov-ered in 1998), which is located 16 miles (25 kilometers)to the west (Fig. 2). Both of these fields have been onproduction since 2004. Other fields in the area includethe BHP Billiton operated Neptune Field, located 16miles (25 km) to the northeast and Shenzi Field, located8 miles (13 km) to the north.

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StructureAtlantis Field is contained within a large salt-

cored, faulted doubly-plunging anticline having four-way closure from the late Miocene to the late Creta-ceous (Fig. 3). The Atlantis closure extends 11 miles(18 kilometers) east-northeast to west-southwest, and 4miles (6.5 km) north-northwest to south-southeast andis characterized by an asymmetrically over steepenedsouthern flank, which has dips up to 70 (Fig. 4). Thestructural crest of the productive middle Miocene reser-voirs is approximately 16,000 feet (4875 meters)TVDSS. The structure is primarily the result of linkedshelf margin extensional tectonics and resulting downslope compressional tectonics. The en echelon geome-try of the folds along this trend (Fig. 2) suggests therealso may be an oblique-slip component to the deforma-tion. The Miocene reservoirs are segmented by twolarge faults in an opposed dip relay parallel to the long

axis of the anticline and by numerous oblique antitheticfaults forming a crestal graben system. A transversegraben system further segments the central area ofstructure related to bending along the long axis fold(Fig. 3).

Two discrete allochthonous salt bodies havesutured over Atlantis, and salt covers approximately60% of the Atlantis structure. The sutured salt bodiesform complex overlapping salt finger and mini-basingeometries (Fig. 4) that adversely impact the seismicimage quality of the north area of the Atlantis structure.Significant effort has been put into improving subsaltseismic image quality from appraisal through currentfield development activities. The extra-salt southernarea of the field has relatively good seismic image qual-ity; fault detection threshold is approximately 50 feet(15 meters) or less of fault offset.

ReservoirThe Atlantis development currently produces

from three of the six discrete Miocene hydrocarbonbearing reservoirs (Fig. 5). The three primary reservoirsbeing developed are middle Miocene in age and repre-sent ~90% of field reserves. The early Miocenehydrocarbon-bearing sands discovered at Atlantis arecorrelative to the primary producing interval in theneighboring Mad Dog and Shenzi fields. At Atlantis,

these reservoirs have lower quality reservoir and fluidsand are not part of the primary development at Atlantis.

The two thickest middle Miocene Atlantis reser-voirs are laterally continuous across the field,consisting of high quality deep-water turbidite sandsdeposited at the base of slope or abyssal plain. Figure 6illustrates the areal extent and estimated sand thicknessof one of these middle Miocene reservoirs. Correlativesands have been penetrated in offset structures; 8 miles

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(13 km) north (Shenzi), 13 miles (21 km) south (Framp-ton), 16 miles (25 km) west (Mad Dog) and 25 miles(40 km) west (Puma) (Fig. 6). They are channelized toamalgamated sheet sands; that display a high net togross ratio. The thickest reservoirs contain over 200feet (60 m) net of sand.

Atlantis middle Miocene reservoirs are domi-nantly fine- to very fine-grained, quartz-rich,

unconsolidated sands which have little clay or cementpresent. Pay sand porosity from well log and core meas-urements is typically between 26% and 32%. Core plugair permeability measurements in net sand range from100 mD to over 5000 mD. Reservoir top seals are pro-vided by middle Miocene shales, which are interpretedas condensed sections related to regional floodingsurfaces.

History of Field DiscoveryAppraisalDevelopment ConceptThe objective of the discovery well (GC 699-1)

was to test the subsalt area of the structure adjacent toNeptune, an early Miocene discovery to the east thatpotentially shared a common spill point. The GC699-1well found 103 feet (30 m) net oil bearing pay in threelevels; two middle Miocene and one early Miocenesand (Fig. 7). The key observation was that the lowerMiocene sands were significantly thinner, but the mid-dle Miocene sands were significantly thicker, than inthe Neptune AT 575-1 discovery well.

Four additional appraisal wells plus five geologi-cal sidetracks were drilled to define the Atlantis Fieldbefore a development sanction decision was made andfunds were committed in 2002. The first appraisal well,GC743-1, (Fig. 7) was drilled extra-salt to test the mid-dle and early Miocene sands updip from the discoverywell on the opposite side of the four-way dip closurefrom the discovery well,. The original hole and GC743-1 ST1 (deviated slightly to the east and) ended opera-tions in July 2000, with extensive bypass and heads-up

coring operations of both middle and early Miocenereservoirs. The results confirmed that the Atlantis struc-ture contained a large stacked-pay hydrocarbonaccumulation, including approximately 400 feet (122meters) net pay in the middle Miocene sands and 170feet (52 m) of net pay in the early Miocene sands.

BP drilled the second appraisal well, GC743-2from a surface location east of the GC743-1 and devi-ated to the north (Fig. 8) to target the middle and earlyMiocene in crestal position in an area of poor seismicimaging. The GC743-2 well reached TD August, 2001,having drilled across a large east-west trending faultthat separates the north and south portions of the Atlan-tis structure (Fig. 8). The middle Miocene pay sandswere faulted out, but early Miocene sands were encoun-tered and contained good quality oil. The well was thensidetracked (GC743-2 ST1) to a target in the south cen-tral area. The well reached TD in October, 2001,finding a total of 305 feet (93 m) net oil pay in the mid-dle Miocene sands.

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The GC743-3 appraisal well, a downdip test foran oil-water contact in the main middle Miocene hori-zons, started drilling July 1, 2002, and finished August10, 2002 (Fig. 9). The well found the middle Miocenemain pay sands wet, but also found 122 feet (37 m) ofnet pay in an overlying middle Miocene sand that wasexpected to be wet in that part of the structure. Thiswell provided key formation pressures in the aquifer ofthe main pay sands, to aid in establishing fluid contactsaround the structure.

From its first discovery to current development,understanding of the Atlantis structure has continuallyevolved, from 2D interpretation in exploration, through3D narrow azimuth towed streamer (NATS) interpreta-tion in appraisal and now Wide Azimuth (WAZ) OceanBottom Node (OBN) interpretation in development(Fig. 10). Advancements in seismic imaging along withdrilling results and dynamic data increasingly revealareas of structural complexity within the Atlantis Field.During Atlantis development planning, scenarios wereevaluated for full or phased development options. How-ever, during the sanction process, it was finally decidedthat a phased development should be utilized at Atlantisand that initial field development should focus on theextra-salt south area that was effectively appraised andhad the best seismic image to manage uncertainty.

At the time of sanction, the NATS 3D seismicdata had poor image quality in the subsalt areas ofAtlantis. The poorly imaged, and at that time, un-appraised north and east areas, along with the highly

faulted center area, were deferred for later phases ofdevelopment. The Atlantis Phase 1 development projectwas sanctioned in November, 2002, and was the fifthand final Gulf of Mexico major project sanctioned byBP during 2001-2002.

About the same time as field sanction, theGC743-5 spudded in November, 2002, to appraise thenorth area of the Atlantis structure. The well reachedTD in January, 2003, and confirmed approximately 324feet (100 m) of net oil pay middle Miocene sands in thenorth flank of Atlantis. The GC743-5BP was drilled totake core in one of the middle Miocene sands andappraise the early Miocene interval. The well reachedTD in February of 2003 and encountered 420 feet (128m) net middle Miocene pay, but all the early Miocenesands were wet. The GC743-5 ST1 well was drilled toan updip location to the southwest and found 393 feet(120 m) of net middle Miocene oil pay, but again theearly Miocene sands were wet. The Atlantis NorthFlank tie-back was sanctioned in 2007 and first produc-tion from the north came online in 2009.

The Atlantis development consists of onesemisubmersible Production Quarters (PQ) facility withwet trees (Fig. 11). Two dedicated Mobile OffshoreDrilling Units (MODUs) are contracted for drilling,completion, well interventions, and subsea installationwork. The PQ was designed with an oil capacity of200,000 bopd, 75,000 bpd produced water handling,75,000 bpd water injection, and 180 MMcf per day gashandling. The south flank of Atlantis is being devel-

Mander et al. 6

oped from Drill Center 1 (DC1) located at the base ofthe Sigsbee escarpment (Fig. 11). The northern area ofAtlantis is being developed from Drill Center 3 (DC3)located on the Sigsbee escarpment (Fig. 11). Contin-gency for water injection is included in the facilitydesign; early production performance will determine ifor when it would be needed.

Given the extensive, thick, high-quality reservoirsands, significant aquifer support was predicted,although compartmentalization by faulting was recog-nized as a risk. Producers were planned to be primarilystacked fracture-pack completions using down-holegauges and down-hole flow control to allow for futurewater cut-off and zonal surveillance. Injectors wereplanned to be single zone frac pack completions.

SeismicSeismic image quality at Atlantis has been a key

driver in the phased development strategy, and despiteextensive efforts it remains a significant focus area toreduce development uncertainty. The exploration andappraisal seismic interpretations utilized 1996 vintageNATS seismic acquired by Western Geophysical. Thisdata was the subject of nearly continuous proprietaryBP depth reprocessing through 2005, but subsalt imagequality was still challenged. This was a contributingfactor to the first phase of development being focusedon the southern better imaged extra-salt field areas.With the emergence of WATS seismic technology toaddress complex subsalt imaging problems, BPacquired the worlds first large scale autonomous OBNwide azimuth 3D survey at Atlantis with FairfieldIndustries in early 2006.

The aim of the OBN acquisition was to get wideazimuth source and receiver offsets (minimum of 3.7miles (6 km) cross-line and 5 miles (8 km) inline) tomaximize the opportunity for subsalt illumination

(Beaudoin and Ross, 2007). In total, 44 node lines weredeployed as were 37 self-powered nodes per line posi-tioned and recovered by ROVs. 1628 nodes were usedin total; good data were recovered from 1615 nodes(Fig. 12). The node area covered approximately 230square kilometers. Water depths in the area ranged fromapproximately 4600 to 7800 feet (1400 to 2380 m). Thesurvey was acquired in two patches: Patch I was on topof Sigsbee Escarpment, Patch II covered the surface ofthe escarpment and the lower portion of the area. Pro-prietary BP OBN seismic depth processing showedimprovement over the earlier NATS imaging in bothextra-salt and subsalt areas. An isotropic velocity modelrebuild and imaging update was completed in 2008 fol-lowed by a vertical transverse isotropy (VTI) velocitymodel and reprocessing in 2009. OBN acquisition andprocessing provided many advantages for building amore accurate salt geometry and subsalt velocity modelat Atlantis, resulting in image improvements in both

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extra-salt and subsalt to improve confidence in devel-opment drilling (Howie et al., 2008).

In 2009, an OBN time lapse survey was acquiredusing 498 of the original 1628 nodes repeated, of which91% were placed within 16 feet (5 m) of the previous2007 node locations. In addition, 98% of source andreceiver locations were within 100 feet (30 m) of origi-nal locations, which represents world class repeatabilityand shows the distinct advantage of OBN surveys forseismic repeatability (Hays et al., 2008). The surveywas designed to detect the variation in pressure deple-tion across the extra-salt Phase 1 south area and also tolook for aquifer movement as water sweeps in aroundthe edges of the reservoir.

In late 2009, BP initiated a project to reprocessthe OBN and NATS seismic using tilted transverse isot-

ropy and reverse time migration (TTI RTM) technologyin an attempt to further improve subsalt imaging andreduce reservoir uncertainty for the Phase 2 develop-ment. The OBN seismic has provided distinctadvantages for building more accurate salt and sedi-ment velocity models and improvements in this effortwere achieved utilizing TTI RTM 3D angle gatherstechnology. Migration of OBN common receiver gath-ers is also more efficient than migration of towed-streamer common shot gathers, which allowed testingof over one hundred different salt scenarios prior toarriving at the preferred velocity model. Each genera-tion of seismic reprocessing has led to improvements inimage quality, but the complexity of the salt over thenorth of Atlantis represents a substantial challenge andhigh quality seismic imaging remains elusive (Fig. 13).

Dynamic Data Pre-production reservoir connectivity studies

were conducted in 2003 and 2006. The studies inte-grated pressure, fluids, geochemical, geological, andgeophysical data to establish potential sealing barriersas well as possible connectivity between different faultblocks. Results suggested that most major faults identi-fiable from the seismic data set should have sealingcapacity somewhere along the faults. Based on this con-clusion pre-production, development wells wereplanned for almost every significant fault block toensure optimal resource recovery. By the fourth quarterof 2006, Atlantis had drilled two additional wells and

completed three short duration flow-backs as part of thepre-drill stage. Investigation into possible causes of thebarriers and baffles included stratigraphic and structuralmechanisms (Fig. 14). Structural causes, primarily sub-seismic faults or related features, were believed to bethe primary mechanism for the baffles with strati-graphic continuity identified as a secondary influence(Fig. 14). Where a reservoir unit is not entirely offset bya fault, shale gauge ratio criteria used for fault-sealevaluation were defined as a function of the shale con-tent of the stratigraphic interval and the amount of faultoffset. Where well pairs were separated by more than

Mander et al. 8

one fault, the number of faults between well pairs wasalso taken into consideration. Pressure differencesrecorded between wells showed that the Atlantis mainreservoirs were in communication across the structure.

First oil was achieved at Atlantis on October 7,2007, from the DC 111 well. Upon startup, productionperformance was characterized by low rates and steeppressure declines (Fig. 15). Initial interpretationsfocused on production rates being impacted by nearwellbore baffles or barriers and weak aquifer connec-tion. These observations were also made on subsequentproduction wells.

Pressure Transient Analysis (PTA) of the initialproduction wells indicated that several barriers and baf-fles to flow were present within 100 to 500 (feet) (30 to150 meters) of the wells. However, none of the wellswere in completely closed compartments, and all con-nected to larger fluid volumes farther away from thewells. Because of the rapid decline in reservoir pres-sure, riser based gas lift was installed within the firstyear. Post-production aquifer support had been identi-fied as a significant uncertainty especially in the southflank. The early south flank production data indicatedthat the central part of the south flank did indeed have

limited aquifer support and would benefit from acceler-ated injection.

First injection was achieved from the DC 102injector in January, 2011, which was completed as asingle zone fracture-pack completion. Pressureresponse and change in decline rate observed at varioussouthwest producers indicated that the injector is con-nected to several updip producers. However, coreacquired in the DC 102 well revealed that the reservoirat this location was suffering from severe deformation.This was confirmed by dynamic performance from thefirst injection well (DC102) which had low injectionrates (~10,000 bwipd). Additional information isrequired to understand how the structural deformationwill affect water injection on the south side of the struc-ture. The acquisition of more cores is planned in theupcoming water injection wells.

Furthermore, water injection above fracture pres-sure in soft sediments has been highly problematicacross the Gulf of Mexico. A comprehensive surveil-lance plan has been developed for the injection well tobetter understand the well and reservoir performance.Permanent down hole gauges have been an invaluablesurveillance tool to ensure the bottom hole injectionpressure does not go above the target pressure.

Refreshed Depositional and Structural DescriptionA fresh study of the depositional and structural

description has been initiated to incorporate knowledgefrom the initial production data. Well pressure build-up

derived permeability estimates are lower than that pre-dicted core plugs or logs. Currently, there are two keystructural features believed to cause the inter-well baf-

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fles that restrict flow in the Atlantis middle Miocenereservoirs. Near-fault baffling is interpreted to becaused by deformation related to movement alongfaults. High-resolution dipmeter and image log dataindicate zones of drag and distributed shear aroundsome, but not all, faults. Recent core acquisition hasrevealed a high density network of deformation bandsexists in some Atlantis reservoirs, especially at thesouthern steeply dipping hinge of the Atlantis structure(Fig. 16). Open-hole pressures were taken along thecored interval and didnt show any continuous fluidgradients. Baffling away from known mapped faultscan be caused by deformation bands which are formedunder certain stress conditions in porous sediments(Aydin and Johnson 1978; Fossen and Hesthammer,1997). In both cases, the reduction to flow capacity iscaused by crushing, re-alignment, and re-packing ofsand grains. In the cases where deformation bands areobserved in whole core (Fig. 16), thin-sections showonly a modest decrease in porosity (3-6%) but three orfour orders of magnitude reduction in permeability. Theeffect is a reduction in bulk permeability across the res-ervoir, even though the permeability of undeformedmatrix is unchanged.

In addition to the impact structural features haveon fluid flow, stratigraphic baffles and barriers wererecognized at an early production stage. A dramaticexample was seen in the DC 142, the first well drilledafter field start-up (Fig. 17). Measured pressuresshowed offset across small gamma ray breaks, but pres-

sures were continuous across an interpreted fault whichhad sand-on-sand juxtaposition (Fig. 17). The DC 142was the first post-production well where it was possibleto observe the effect of stratigraphy on pressure deple-tion in the sand units. The pressure points revealeddepletion between 200 to 100 psi from the originalundepleted pressure gradient and several zones of dif-ferent levels of depletion within the Atlantis reservoirsands. The insights gained from post production wellswith pressure depletion were that inter-well connectiv-ity was impacted by both structural and stratigraphiccomplexity.

Although the Atlantis reservoir sands are highnet-to-gross and relatively isopachous, there are varia-tions in facies, pinchouts, and onlaps at the finer scale.For example, some sand bodies in wells on the flanks ofthe structure are thinner or absent in the more crestalwells, which may have an effect on flow conformancebetween downdip water injectors and the updip produc-ers. One of the wells having a core through a gammaray spike demonstrates that this heterolithic interval hasbeen deposited in a very low energy environment and isin extreme contrast with adjacent sands (Fig. 18).

Bioturbation in this interval attests to time repre-sented by these muddy sections. Similar gamma spikesappear in other wells in Atlantis at different strati-graphic levels. The nature and extent of theheterogeneities is unknown. Although pre-productionpressures seem to exclude field-wide extensive mud-prone units, it is possible that later erosion by subse-

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quent high-energy sand supply pulses has removedsome of the previously more extensive muddy units.Current sedimentological studies are trying to improvethe resolution of the internal lobe architecture.

Although the earlier interpretation was mainlyfocused on a multi-lobe complex scale (Prelat et al.,2009), present studies are trying to interpret individuallobe complexes, which in turn are used to discern stack-ing patterns and lateral arrangements that will havedifferent connectivity associated with them (Fig. 19).Outbuilding, growth, and retreat are used to describethe development of the lobe complex through time(Hodgson et al., 2006). Recognition of these differentcycles is important as associated connectivities will be

different in these stages. Although good connectivitiescan be expected between and within sand bodies of thegrowth stage, an outbuilding stage feeder system willhave little to no connectivity between isolated andsmall scale depositional elements. Spatial distributionof a shingled system will result in a mix of proximal todistal facies in a single system and therefore imply vari-ability in horizontal connectivity. A more fixed systemwould result in good connectivity between sand bodiesin all parts of the system. These refined depositionalmodels in addition to an improved understanding of thestructural complexities can be used to explain varia-tions in performance observed across the Atlantisproducers.

ConclusionAtlantis Field was discovered in 1998 and

achieved first oil on October 6, 2007. As of June 1,2012, the Atlantis structure has been penetrated by 31well bores and all have found hydrocarbons. Atlantishas currently 10 producing wells and one active injectorwell with a second injector currently forecasted to bedrilled by December, 2012. Gross cumulative produc-tion as of April 1, 2012 was 133 mmstbo (147 mmboe).Several technologies have been important to the Atlan-tis success, including down hole flow control, real timedown hole pressure gauges, and the use of Ocean Bot-tom Nodes (OBN) technology in seismic imaging. A lothas been learned since the original discovery of Atlantisand studies to improve knowledge of the dynamic

behavior of the field are continuous. A high priority issubsalt seismic imaging which is critical to improveimage quality in the north, east, and south central areasfor future well placement and water-flood management.The understanding of the impact of structural and strati-graphic complexity on well performance is beingimproved and investigated at different scales focusingon internal fabric and heterogeneities of the reservoirs.More cores are being acquired from the field. Chal-lenges going forward include appraisal anddevelopment of remaining segments and reservoirs ofthe field, efficient operation of the wells, subsea archi-tecture, and production facilities. Despite variouschallenges encountered since first oil in 2007, Atlantis

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Field has benefited from significant improvements toseismic imaging since and the team is continuing to

improve understanding of the subsurface to better sup-port field development activities.

AcknowledgmentsMany people have been involved in the history of

the Atlantis Field from the time of its discovery to firstproduction. The success of bringing this field to devel-opment relied on the efforts of many support teams andthe contributions of many people during the past andpresent. We thank BP and co-owner BHP Billiton forpermission to publish this paper and present at theGCSSEPM Foundation conference. Special mentionshould go to Srini Prasad, Carolina Torres, and JohnHowie as current and previous Team Leaders; theAtlantis Geophysics team for managing the OBN seis-

mic acquisition and reprocessing program; Zeke Snowfor his structural analysis of deformation bands inAtlantis; and Atlantis Geoscientists past and presentincluding consultants Badley Ahston for middle Mico-ene stratigraphic interpretations. Furthermore we wouldlike to thank Pramod Singh, Vice President of BP GOMResource, Jim Brenneke, Geoscience Discipline LeadBP GoM Deepwater Production, and Chris Walker,Structural Geologist Mad Dog Reservoir Management,for taking their time to review this paper.

References

Aydin, A. and Johnson, A. M., 1978, Development of faultsas zones of deformation bands and as slip surfaces insandstone: Pure and Applied Geophysics, v. 116, no.4-5, p. 931-942.

Beaudoin, G. and A.A. Ross, 2007, Field Design and Opera-tion of a Novel Deepwater, Wide-Azimuth Node Seis-mic Survey: The Leading Edge, vol. 26, p. 494-503.

Fossen, H., and J. Hesthammer, 1997, Geometric analysisand scaling relations of deformation bands in poroussandstone: Journal of Structural Geology, v. 19, no..12, p.1479-1493.

Hays, D., K. Craft, P. Docherty, and F. Smit, 2008, An OceanBottom Seismic node repeatability study: 71st EAGEConference & Exhibition, SEG, Expanded Abstracts

Hodgson, D.M., S.S. Flint, D. Hodgetts, N.J. Drinkwater,E.P. Johannessen and S. Luthi, 2006, Stratigraphicevolution of fine-grained submarine fan systems, Tan-qua depocentre, Karoo Basin, South Africa: Journal ofSedimentary Research, v. 76, p. 20-40.

Howie, J., P. Mahob, D. Shepherd, and G. Beaudoin, 2008,Unlocking the Full Potential of Atlantis with OBSNodes: 76th Annual International Meeting, SEG,Expanded Abstracts.

Mander et al. 12

Prelat A, D.M. Hodgson, S.S. Flint, 2009, Evolution, archi-tecture and hierarchy of distributary deep-waterdeposits: a high-resolution outcrop investigation from

the Permian Karoo Basin, South Africa: Sedimentol-ogy, v.56, p.2132-U25.

Mander et al. 13

Figure 1. Gulf of Mexico bathymetry map showing geographic location of Atlantis in the western Atwater Fold Belt. Red color representsshallow and blue represents deeper bathymetry.

Mander et al. 14

Figure 2. Regional structure map of the early Miocene reservoir horizon showing linear fold and circular salt structures. Yellow areas arehigh, purple areas are low, and cyan represents salt. Individual squares represent Gulf of Mexico lease blocks which are generally 3 milesby 3 miles (~ 4.8 by 4.8 kilometers).

Neptune

Frampton

Puma

K2/Timon

Shenzi

Green Knoll

Atlantis

Mad Dog

Large Structures

Atlantis

Mad Dog

Shenzi

Neptune

Puma

Frampton

Green Knoll

Extent of salt canopy

Mander et al. 15

f

Figure 3. Left: Atlantis geologic cross-section, showing relative locations of the first and fifth appraisal wells (Line of section is indicated bythe white line on the map); Right: Atlantis structural map of middle Miocene horizon red representing high purple representing low.Grey shaded area represents area masked by the overlying salt.

Mander et al. 16

Figure 4. Atlantis 3D perspective of the seafloor, salt and reservoir, showing also location of two drill centers (DC1 and DC3). Red areas arehigh and green/blue are low.

DC1

DC3

Top middle Miocene Depth Structure

Water BottomTop Salt

Base Salt

~1.5 miles

~11 Mil

es +

~4 Miles

Scale of Atlantis anticline

DC1

DC3

Top middle Miocene Depth Structure

Water BottomTop Salt

Base Salt

~1.5 miles

~11 Mil

es +

~4 Miles

Scale of Atlantis anticline

Mander et al. 17

Figure 5. Atlantis summary stratigraphic col-umn for the middle/early Miocene interval.Reservoirs for development are highlightedby squares; pink squares represent the twomajor Atlantis reservoirs. Left track showsgamma ray log; sands highlighted in yellow,right track represents deep resistivity logwith pay highlighted in green. Orange boxesrepresent geologic epoch.

Cyclicargolithus floridanus

Sphenolitus heteromorphus

Discoaster petaliformis

Praeorbuling glomerosa

Helicosphaera ampliaperta

Catapsydrax dissimilis

Sphenolithus belemnos

Early

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Figure 6. Middle Miocene sand deposition map and regional stratigraphic correlation for southern Green Canyon Area. Middle Miocenesands are laterally extensive and correlatable from field to field across southern Green Canyon area.

GC782 #4OH GC826 #1BP1 GC783 #1 GC872 #1 GC785 #1 GC743 #3 GC743 #1ST2 GC743 #1OH GC743 #6 GC743 #5ST1 GC743 #5BP1 GC743 #2ST1 GC699 #1WB2Mad Dog Frampton Dendara Atlantis

Regional Stratigraph ic Se ctio n

M57

M55

M54

M53

20 Miles

SW

4.4 Miles

25 miles/ 40 kilometers

Fra mpton

K2/T imon

ShenziNeptune

At la nt isM ad Do g

Pu ma

De nda ra

Middle M iocene SandTurbidite Depositional System

Gre en Knoll

118

281 211

0

Well Cont rol

Stru cture

L egen d

Net Sa nd Cont our

Reg ional Cros s Sec tion

(~32 ki lom eter s)

(~7 ki lometers)



M57

M55

M54

M53

20 Miles

SW

4.4 Miles


Fra mpton

K2/T imon

ShenziNeptune


Pu ma

De nda ra


Gre en Knoll

118

281 211

0

Well Cont rol

Stru cture

L egen d

Net Sa nd Cont our




M57

M55

M54

M53

20 Miles

SW

4.4 Miles


Fra mpton

K2/T imon

ShenziNeptune


Pu ma

De nda ra


Gre en Knoll

118

281 211

0

Well Cont rol

Stru cture

L egen d

Net Sa nd Cont our


(~32 ki lom eter s)

(~7 ki lometers)

100

250

CI: 50 feet

Mander et al. 19

Figure 7. (A) Discovery well GC699; (B) First appraisal well GC743-1 and ST1, showing maps used for well location definition at the timeof drilling these wells. Left tracks shows gamma ray log with sands highlighted in yellow, right tracks represents deep resistivity log withpay highlighted in green.

35 API

25 API

M55

M54

M53

M20

M15

GC 699#1 WB02

Discovery Well1998

Discovery Well1998

Miocene:390 net sand 90 net pay

100 Mid

dle

Mio

cene

Early

Mio

cene

A)

35 API

25 API

M55

M54

M53

M20

M15

GC 699#1 WB02

Discovery Well1998

Discovery Well1998


100 Mid

dle

Mio

cene

Early

Mio

cene

35 API

25 API

M55

M54

M53

M20

M15

GC 699#1 WB02

Discovery Well1998

Discovery Well1998


100100 Mid

dle

Mio

cene

Early

Mio

cene

A)

Middle Mioc ene Pay: 300

Early Miocene Pay: 215

GC699#1 WB02 GC743#1 SW F lank Test2000

Cor

eC

ore

Co

reC

oreP li ocene

Gamma Ray0 120

Resistivity0.2 200

15000

15500

16000

16500

17000

17500

18000

TVDFEET

Mid

dle

Mio

cene

Late

Mio

.Ea

rly

Mio

cene

AGE

Plio .

B)2000

Cor

eC

ore

Co

reC

oreP li ocene

Gamma Ray0 120

Resistivity0.2 200

15000

15500

16000

16500

17000

17500

18000

TVDFEET

Mid

dle

Mio

cene

Late

Mio

.Ea

rly

Mio

cene

AGE

Plio .

Cor

eC

ore

Co

reC

ore

Co

reP li ocene

Gamma Ray0 120

Resistivity0.2 200

Gamma Ray0 120

Resistivity0.2 200

15000

15500

16000

16500

17000

17500

18000

TVDFEET

15000

15500

16000

16500

17000

17500

18000

TVDFEET

Mid

dle

Mio

cene

Late

Mio

.Ea

rly

Mio

cene

AGE

Plio .

B)

35 API

25 API

M55

M54

M53

M20

M15

GC 699#1 WB02

Discovery Well1998

Discovery Well1998


100 Mid

dle

Mio

cene

Early

Mio

cene

A)

35 API

25 API

M55

M54

M53

M20

M15

GC 699#1 WB02

Discovery Well1998

Discovery Well1998


100 Mid

dle

Mio

cene

Early

Mio

cene

35 API

25 API

M55

M54

M53

M20

M15

GC 699#1 WB02

Discovery Well1998

Discovery Well1998


100100 Mid

dle

Mio

cene

Early

Mio

cene

A)

Middle Mioc ene Pay: 300

Early Miocene Pay: 215

GC699#1 WB02 GC743#1 SW F lank Test2000

Cor

eC

ore

Co

reC

ore

Co

reP li ocene

Gamma Ray0 120

Resistivity0.2 200

Gamma Ray0 120

Resistivity0.2 200

15000

15500

16000

16500

17000

17500

18000

TVDFEET

15000

15500

16000

16500

17000

17500

18000

TVDFEET

Mid

dle

Mio

cene

Late

Mio

.Ea

rly

Mio

cene

AGE

Plio .

B)2000

Cor

eC

ore

Co

reC

ore

Co

reP li ocene

Gamma Ray0 120

Resistivity0.2 200

Gamma Ray0 120

Resistivity0.2 200

15000

15500

16000

16500

17000

17500

18000

TVDFEET

15000

15500

16000

16500

17000

17500

18000

TVDFEET

Mid

dle

Mio

cene

Late

Mio

.Ea

rly

Mio

cene

AGE

Plio .

Cor

eC

ore

Co

reC

ore

Co

reP li ocene

Gamma Ray0 120

Resistivity0.2 200

Gamma Ray0 120

Resistivity0.2 200

15000

15500

16000

16500

17000

17500

18000

TVDFEET

15000

15500

16000

16500

17000

17500

18000

TVDFEET

Mid

dle

Mio

cene

Late

Mio

.Ea

rly

Mio

cene

AGE

Plio .

B)

Mander et al. 20

Figure 8. Second appraisal well GC743#2 crestal test followed by GC743#2ST1, showing maps used for well location definition at the timeof drilling these wells. Left tracks shows gamma ray log, right tracks represents deep resistivity log with pay highlighted in green (oil) orred (gas).

AGE

Mid

dle

Mio

cene

Gamma Ray0 200

Resistivi ty0.2 200

16000

16500

TVDFEET

UpperMiocene

Crestal Test2001

Miocene pay: 114

Ear

ly M

ioce

ne17000

GC743#2 GC743#2 ST1

Middle Miocene320 net pay

SE Flank Sidetrack2001

Gamma Ray0 200

Resistivity0.2 2000

AGE

Plei

st.

Mid

dle

Mio

cene

Late

M

ioce

ne

14500

15000

15500

16000

16500

17000

TVDFEET

AGE

Mid

dle

Mio

cene

Gamma Ray0 200

Resistivi ty0.2 200

16000

16500

TVDFEET

UpperMiocene

Crestal Test2001

Miocene pay: 114

Ear

ly M

ioce

ne17000

GC743#2 GC743#2 ST1

Middle Miocene320 net pay

SE Flank Sidetrack2001

Gamma Ray0 200

Resistivity0.2 2000

Gamma Ray0 200

Resistivity0.2 2000

AGEAGE

Plei

st.

Mid

dle

Mio

cene

Late

M

ioce

ne

14500

15000

15500

16000

16500

17000

TVDFEET

Mander et al. 21

Figure 9. Appraisal well GC743#3 to test oil-water contacts in Atlantis, showing maps used for well location definition at the time of drill-ing these wells. Left tracks shows gamma ray log, right tracks represents deep resistivity log with pay highlighted in green (oil) or red (gas).

M53

Gamma R ay0 120

R esistiv ity0.2 200

AG E

15 000

15 500

16 000

16 500

17 000

17 500

18 000

18 500

19 000

TVDSSFEET

126 net pay- API - 21.9 API- GOR ? 816 SSF

~80 net pay (gas)

Midd

le Mio

cene

Late

Mioce

ne

Plioce

ne

Pleist.

1 00 ft

GC743#3

SW Flank Oil Water Contact

210 net wet sand

130 net wet sandM53

Gamma R ay0 120


AG E

15 000

15 500

16 000

16 500

17 000

17 500

18 000

18 500

19 000

TVDSSFEET

M53

Gamma R ay0 120


Gamma R ay0 120


AG E

15 000

15 500

16 000

16 500

17 000

17 500

18 000

18 500

19 000

TVDSSFEET

15 000

15 500

16 000

16 500

17 000

17 500

18 000

18 500

19 000

TVDSSFEET

126 net pay- API - 21.9 API- GOR ? 816 SSF

~80 net pay (gas)

Midd

le Mio

cene

Late

Mioce

ne

Plioce

ne

Pleist.

1 00 ft1 00 ft

GC743#3



210 net wet sand

130 net wet sand

Mander et al. 22

Figure 10. Atlantis maps progression through time, showing how increase in well penetrations, improvement of seismic data coverage andquality and acquisition of dynamic data have revealed increasing structural complexity of the Atlantis field over time. Block sizes are 3miles by 3 miles.

Mander et al. 23

Figure 11. Atlantis seafloor topography showing Sigsbee Escarpment and development concept.

6,818

1 mile M.C. WilliamsNImage of Se a Floor vie wed from

azimuth 1 80o, ele vation 25o , VE=1

DDII

DC1

DC3GC743-3

DC2DC5

5,404

6,818

1 mile M.C. WilliamsNImage of Se a Floor vie wed from

azimuth 1 80o, ele vation 25o , VE=1

DDII

DC1

DC3GC743-3

DC2DC5

5,404

Mander et al. 24

Figure 12. OBS Node Solution for Atlantis showing a self powered node and to the right nodes locations inred showing the challenging Sigsbee Escarpment bathymetric variation with water depths in the area rang-ing from approximately 4500ft (1400 m) to 7000ft (2070 m).

4500 feet (1370 m)

7000 feet (2070 m)

Mander et al. 25

Figure 13. Example of improvement in processing over time, from single azimuth NATS in 2003 to OBN wide azimuth 3D data. An isotro-pic velocity model rebuild and imaging update was completed in 2008. In late 2009, BP decided to reprocess the OBN and NATS seismicusing tilted transverse isotropy and reverse time migration (TTI RTM) technology in an attempt to further improve sub-salt imaging andreduce reservoir uncertainty for the Phase 2 development. The TTI RTM imaging was completed in late 2010.

Single Azimuth NATS, Isotropic CAW E - 2003

OBN WAZ, Isotropic SM -2008

OBN WAZ & NATS Merge, TTI RTM -2010

3000

9000

VE 2.7:1

Single Azimuth NATS, Isotropic CAW E - 2003

OBN WAZ, Isotropic SM -2008

OBN WAZ & NATS Merge, TTI RTM -2010

3000

9000

VE 2.7:1

9000

VE 2.7:1

Mander et al. 26

Figure 14. Potential geologic causes for sub-seismic production baffles.

Statistically predicted

Mander et al. 27

Figure 15. Dynamic data (Rate, Pressure,Productivity Index (PI)) for DC111 firstproduction well.

Rate

Well 6 (B4-F) Pre ssure Data

0

2000

4000

6000

8000

10000

0 730 1460 2190 2920 3650 4380 5110 5840Time (days)

Pre

ssu

re (

psia

)

Ac tua l FBHP

PressureActual

We ll 6 (B4-F) Ratio & PI Data

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

18.0

20.0

0 730 1460 2190 2920 3650 4380 5110 5840Time (days)

PI (

Liq

uid

Rat

e/(P

i-PB

OP

D/P

si)

Actual FBHP

PIActual

Well 6 (B4-F) Rate Data

0

5000

10000

15000

20000

25000

30000

35000

40000

0 730 1460 2190 2920 3650 4380 5110 5840Tim e (days)

Rat

es (b

pd,m

scfd

)

Actual OilWater Rate (BWPD)

RateActual

Mander et al. 28

Figure 16. Atlantis core showing high density deformation band network. At core scale, they are whitish lines (about 1mm wide) that inter-sect each other into a network. At microscope scale (shown on SEM image of thin sections made from core-plugs where red circle) defor-mation bands cause the reduction to flow capability by porosity collapse, grain crushing, re-alignment and frictional sliding. Figure showsan example of a core interpreted for different deformation band sets, each characterized by different orientation of principal stresses.

DB

1foot

0.1 foot

Mander et al. 29

Figure 17. Differential pressure depletion observed in DC142(D) well with recorded pressures from produced middle Miocene reservoirsshown in blue and original pressure line of these middle Miocene reservoirs shown in green. The figure demonstrates correlation to shalefacies (grey on facies log) and, therefore, stratigraphically controlled. On the facies log, shales/silts are grey/purple and sands are yellow,orange, and red. On the right, image logs are shown, interpreted (left) and uninterpreted (right), followed by dipmeter track with highangle features (HAF) circled in red, which are interpreted to represent a fault.

Mander et al. 30

Figure 18. Example of cored Atlantis reservoir heterogeneity, showing one of the gamma ray spikes seen inthe reservoirs which shows bioturbated, mud-prone low energy interval in the photo inset. Red curve rep-resents gamma ray, track behind represents interpreted core log.

Mander et al. 31

Figure 19. Stacking patterns and lateral arrangements of lobe systems through time (from Badley Ashton America Inc).

AbstractIntroductionStructureReservoirHistory of Field DiscoveryAppraisalDevelopment ConceptSeismicDynamic DataRefreshed Depositional and Structural DescriptionConclusionAcknowledgmentsReferencesFigures1. Gulf of Mexico bathymetry map showing geographic location of Atlantis in the western Atwater Fold Belt. Red color represents shallow and blue represents deeper bathymetry.2. Regional structure map of the early Miocene reservoir horizon showing linear fold and circular salt structures. Yellow areas are high, purple areas are low, and cyan represents salt. Individual squares represent Gulf of Mexico lease blocks ...3. Left: Atlantis geologic cross-section, showing relative locations of the first and fifth appraisal wells (Line of section is indicated by the white line on the map); Right: Atlantis structural map of middle Miocene horizon red represent...4. Atlantis 3D perspective of the seafloor, salt and reservoir, showing also location of two drill centers (DC1 and DC3). Red areas are high and green/blue are low.5. Atlantis summary stratigraphic column for the middle/early Miocene interval. Reservoirs for development are highlighted by squares; pink squares represent the two major Atlantis reservoirs. Left track shows gamma ray log; sands highlighted ...6. Middle Miocene sand deposition map and regional stratigraphic correlation for southern Green Canyon Area. Middle Miocene sands are laterally extensive and correlatable from field to field across southern Green Canyon area.7. (A) Discovery well GC699; (B) First appraisal well GC743-1 and ST1, showing maps used for well location definition at the time of drilling these wells. Left tracks shows gamma ray log with sands highlighted in yellow, right tracks represent...8. Second appraisal well GC743#2 crestal test followed by GC743#2ST1, showing maps used for well location definition at the time of drilling these wells. Left tracks shows gamma ray log, right tracks represents deep resistivity log with pay hi...9. Appraisal well GC743#3 to test oil-water contacts in Atlantis, showing maps used for well location definition at the time of drilling these wells. Left tracks shows gamma ray log, right tracks represents deep resistivity log with pay highli...10. Atlantis maps progression through time, showing how increase in well penetrations, improvement of seismic data coverage and quality and acquisition of dynamic data have revealed increasing structural complexity of the Atlantis field over t...11. Atlantis seafloor topography showing Sigsbee Escarpment and development concept.12. OBS Node Solution for Atlantis showing a self powered node and to the right nodes locations in red showing the challenging Sigsbee Escarpment bathymetric variation with water depths in the area ranging from approximately 4500ft (1400 m) to...13. Example of improvement in processing over time, from single azimuth NATS in 2003 to OBN wide azimuth 3D data. An isotropic velocity model rebuild and imaging update was completed in 2008. In late 2009, BP decided to reprocess the OBN and N...14. Potential geologic causes for sub-seismic production baffles.15. Dynamic data (Rate, Pressure, Productivity Index (PI)) for DC111 first production well.16. Atlantis core showing high density deformation band network. At core scale, they are whitish lines (about 1mm wide) that intersect each other into a network. At microscope scale (shown on SEM image of thin sections made from core-plugs whe...17. Differential pressure depletion observed in DC142(D) well with recorded pressures from produced middle Miocene reservoirs shown in blue and original pressure line of these middle Miocene reservoirs shown in green. The figure demonstrat...18. Example of cored Atlantis reservoir heterogeneity, showing one of the gamma ray spikes seen in the reservoirs which shows bioturbated, mud-prone low energy interval in the photo inset. Red curve represents gamma ray, track behind represent...19. Stacking patterns and lateral arrangements of lobe systems through time (from Badley Ashton America Inc).

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