georges bank petroleum exploration - boem · 2019. 10. 14. · leasing history federal offshore...

OCS ReportMMS 2000-031

GEORGES BANK PETROLEUMEXPLORATION

Atlantic Outer Continental Shelf

By Gary M. EdsonDonald L. OlsonAndrew J. Petty

U.S. Department of the InteriorMinerals Management ServiceGulf of Mexico OCS Region New OrleansOffice of Resource Evaluation May 2000

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GEORGES BANK PETROLEUM EXPLORATIONATLANTIC OUTER CONTINENTAL SHELF

Ten wells were drilled on Georges Bank, offshore from New England, from 1976 through1982 (table 1, figure 1). The first two wells were Continental Offshore Stratigraphic Test(COST) wells, drilled during 1976 and 1977 by energy company consortiums to gaingeologic information prior to offshore Federal petroleum exploration leasing. After leaseswere awarded, eight industry exploration wells were drilled in 1981 and 1982. None of theseencountered significant concentrations of oil or natural gas, and drilling has not resumedsince 1982. Records and data from the wells are maintained by the Minerals ManagementService (MMS), Department of the Interior, at the Gulf of Mexico OCS Region office, 1201Elmwood Park Boulevard, New Orleans, Louisiana 70123-2394, (504) 736-0557. Summaries and analyses of data from the industry exploration wells are contained in eightGeological and Operational Summary publications accompanying this report.

Table 1. Georges Bank wells

ProtractionDiagram

Block WellNo.

Well Typeor

COST No.

Operator SpudDate

MeasuredDepth (ft)

NK 19-9 975 1 Exploration Exxon 11-25-81 14,605NK 19-11 79 - COST G-1 Ocean Production 04-06-76 16,071NK 19-12 133 1 Exploration Exxon 07-24-81 14,118NK 19-12 141 - COST G-2 Ocean Production 01-06-77 21,874NK19-12 145 1 Exploration Conoco 05-13-82 14,500NK19-12 187 1 Exploration Tenneco 03-12-82 18,127NK 19-12 273 1 Exploration Mobil 06-30-82 15,580NK 19-12 312 1 Exploration Mobil 12-08-81 20,000NK 19-12 357 1 Exploration Shell 04-14-82 19,427NK 19-12 410 1 Exploration Shell 08-10-81 15,568

Names of protraction diagrams are: NK 19-9, Corsair Canyon; NK 19-11, Hydrographer Canyon; NK 19-12,Lydonia Canyon. COST is Continental Offshore Stratigraphic Test.

LEASING HISTORY

Federal offshore Lease Sale 42, held onDecember 18, 1979, was the onlysuccessful North Atlantic Planning Area(Georges Bank) lease offering. Sixty-threeblocks were leased to companies for

bonus bids totaling $816,516,546. Subsequent sales (Numbers 52, 82, and96) were canceled. Beginning in 1982, theUnited States Congress enacted a series ofone-year leasing moratoria on portions ofthe Outer Continental Shelf, and thesegrew in area to include Federal waters

CONOCOBLK. 145 NO. 1

EXXONBLK. 975 NO. 1

COST NO. G-1

COSTNO. G-2

EXXONBLK. 133 NO. 1

MOBILBLK. 312 NO. 1

SHELLBLK. 357 NO. 1

SHELLBLK. 410 NO. 1

TENNECOBLK. 187 NO. 1

MOBILBLK. 273 NO. 1

EXPLANATION

Leased Tracts Sale 42 (1979)

Dry Hole

ChathamNK 19 - 8

Corsair CanyonNK 19 - 9

Hydrographer CanyonNK 19 - 11

0 10 20 STATUTE MILESAREA OF INTEREST

MA.

RI.Atlantic Ocean

68

68

41

40 4030' 00" 30' 00"

41

67

67

100

M

200

M

Lydonia CanyonNK 19 - 12

Figure 1. Map of the North Atlantic offshore area showing well locations. Bathymetry in meters.

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along the entire United States Atlanticcoast. On June 12, 1998, PresidentClinton issued an executive order thatprevents the leasing of any area currentlyunder moratorium until June 30, 2012. All of the 1979 Georges Bank leases havenow been relinquished or have expired.

Since 1988, a leasing moratorium has alsobeen in effect on the Canadian portion ofGeorges Bank, which is underlain by theEast Georges Bank Basin, to the northeastof the Yarmouth Arch (figure 2). Texaco,BP-Amoco, and Chevron hold three largeexploration concessions there. Exclusiveexploration rights belonging to thesecompanies remain intact but are suspendedfor the duration of the moratorium. Thismoratorium was reviewed in 1996 through1999, and the review committeerecommended that the suspension ofexploration be extended to 2012, matchingthe adjoining U. S. moratorium. The NovaScotian and Canadian governmentsaccepted this recommendation.

EXPLORATION HISTORY

Seismic service companies acquired morethan 100,000 line miles of seismic data bypermit in the North Atlantic Planning areasince 1966 (figure 3). Between 1966 and1990 there were two accelerated periods ofseismic data acquisition. More than40,000 line miles were shot from 1974through 1977 as companies evaluated thebasin before Lease Sale 42. In 1981 and1982, more than 33,000 line miles wereshot in the years that the exploration wellswere drilled.

The COST G-1 well was drilled 89 statutemiles east-southeast of Nantucket Island inBlock 79 of OCS protraction diagramNK 19-11 (Hydrographer Canyon). Drilling took place from April throughJuly of 1976 to a measured depth of16,071 feet. (All depths cited in thisreport are measured depths, i.e., relative tokelly bushing.) From January throughAugust of the following year, the COSTG-2 well was drilled 43 miles farther east-southeast in Block 141 of NK 19-12(Lydonia Canyon) to a measured depth of21,874 feet. Water depths were 157 and272 feet, respectively. Both wells wereintentionally drilled off-structure, that is,at locations where petroleumaccumulations are unlikely, according toanalysis of seismic data.

The COST wells were intended to providestratigraphic and other geologic andengineering data useful to companies andthe Government in preparing for the NorthAtlantic lease sale. In addition,evaluation of subsequently drilled industrywells would be aided by comparison withCOST well analytic results, and all thewells could be correlated by means ofseismic data and wireline logs.

The up-dip G-1 well (figure 4) penetratedCenozoic and Mesozoic siliciclasticsedimentary rocks to a depth in excess of9,000 feet (Upper Jurassic); interbeddedMiddle and Lower (?) Jurassicsiliciclastics and limestone from about9,000 to about 12,000 feet; and below thatto total depth, Lower Jurassic (?) andTriassic (?) interbedded siliciclastics,dolomite, anhydrite, and minor limestone.

Figure 2. Map of Georges Bank and the Scotian Shelf, showing sedimentary basin locations, areas of Canadian petroleum leases, and 200-meter (shelf-edge) isobath.

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Landward edgeof Mesozoic basins

Canada - Nova Scotiapetroleum leases


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Canada - Nova Scotiapetroleum leases

Explanation

Halifax

0 50 100 Miles

SableIsland

46o

44o

42o

Figure 4. Lithologic columns of the Georges Bank COST G-1 and G-2 wells. Adapted from Amato and Simonis (1980).

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DEPTH

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COSTNO. G-1

COSTNO. G-2

67 KILOMETERS42 STATUE MILES

TD 16,071 ft.

PaleozoicDolomite and

Phyllite

Halite

TD 21,874 ft.

Siliciclastics

Siliciclasticsand

Limestone

Limestone

Siliciclastics, Dolomite,Anhydrite and

Minor Limestone

Dolomite, Anhydrite, Limestone, and Minor

Siliciclastics

andSiliciclastics

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The well bottomed in metamorphicbasement at a measured depth of 16,071feet.

The down-dip G-2 well encountered ahigher proportion of carbonate rocks. Limestone began at about 2,400 feet(Upper Cretaceous) and was interbeddedwith siliciclastics to about 10,000 feet. Below that, in Middle Jurassic (?) toUpper Triassic (?) strata, the proportion ofsiliciclastics was subordinate, andlimestone dominated to about 13,500 feet,with dolomite and anhydrite, subordinatelimestone, and minor siliciclastics belowthat to total depth. This well bottomed inUpper Triassic or Lower Jurassic haliteand anhydrite at a depth of 21,874 feet.

Federal regulations direct the Departmentof the Interior to release COST wellgeologic data to the public 60 days after alease is granted within 50 nautical miles ofwell sites. Leases from OCS Sale 42 weregranted in February of 1980, and theConservation Division of the U.S.Geological Survey (USGS) released openfile reports on the two wells (Amato andBebout, 1980; Amato and Simonis, 1980).In 1982 the Geologic Division of USGSreleased Geological Survey Circular 861(Scholle and Wenkam), which coveredboth wells. These publications areavailable from USGS InformationServices, Box 25286, Denver FederalCenter, Denver, CO 80225, Tel:303-202-4700; Fax: 303-202-4693.

Eight exploration wells were drilled on the63 Georges Bank leases during 1981 and1982. All wells (figure 1) were within 42miles of one another in the main, unnamed

subbasin, where the sedimentary section isthickest. Water depths ranged from 209 to453 feet, and measured well depths from14,118 to 20,000 feet. The companies’exploration targets, stated in theirExploration Plans, were mostly identifiedas Middle or Upper Jurassic (one LowerJurassic) oolite banks, reefal buildups, andcarbonate drape structures over basementhighs or salt swells. Some predrillinginterpretations predicted enhancedporosity, caused by dolomitization. Theseismic features, from which these targetswere inferred, were all high-amplitudereflectors with apparent structural closure.Located between two and three seconds,two-way travel times, the crests of thesefeatures were expected to be between9,000 and 16,000 feet. These depths arewithin the Jurassic carbonate section of theCOST G-2 well and the interbeddedJurassic carbonate and siliciclastic sectionof the G-1 well.

Hydrocarbons were not discovered onGeorges Bank, and target-depth rocks inthe exploration wells were similar tocoeval COST well strata. Instead ofreservoir-quality, porous carbonates, low-porosity micrites, wackestones, andpackstones were the usual limestone typesencountered. As in the COST wells,dolomite and anhydrite interbeds arecommon below about 12,000 feet (figure4). At these depths, the Exxon LydoniaCanyon (LC) Block 133 No. 1 wellencountered intrusive and extrusivevolcanic rocks interbedded with limestone.The Exxon Corsair Canyon 975 No. 1 wellpenetrated halite and anhydriteinterbedded with limestone below about13,000 feet. In these two wells, seismic

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velocity contrasts between volcanics andlimestone and between anhydrite andhalite would produce high-amplitudereflectors. For other Georges Bankexploration well sites, the company-targeted, high-amplitude reflectors appearto be associated with anhydrite-limestoneor anhydrite-siliciclastic velocitydifferences, rather than beinghydrocarbon-related “bright spots.”

Since petroleum exploration began inCanadian waters offshore from NovaScotia in the 1950's, over 290,000 line-miles of 2D and 3D seismic data havebeen collected. One hundred and sixty-seven wells have been drilled (102exploration, 26 delineation, 38 production,and 1 special relief), and 24 significantpetroleum discoveries have been made,mostly natural gas. Most reservoirs are inLower Cretaceous and Upper Jurassicdeltaic sandstones at depths of 9,000-16,000 feet, and many are overpressured(below about 13,500 feet). Traps areanticlinal and/or fault-related.

Near Sable Island, the small Panukemultifield oil project is undergoingabandonment after recovering 44.4 millionbarrels of “Scotian Light” crude oil. Alsonear the island, a Mobil, Shell, and Exxonconsortium, operating as Sable OffshoreEnergy Inc. (SOEI), is developing six gasfields. Three fields are producing gas,which is shipped to Country Harbor, N.S.,by way of the 30-inch Maritimes andNortheast Pipeline. The most recentdiscovery, announced in February 2000 byPanCanadian Petroleum Ltd., is also nearSable Island. In well tests, gas flowed atrates up to 55 million cubic feet per day.

This discovery is the first in an UpperJurassic reef play that goes from offshoreNewfoundland to Florida.

A third phase of petroleum exploration isbeginning in most areas of the NovaScotian offshore, including the UpperPaleozoic Sydney and Magdalena Basinsand previously unexplored deepwaterTertiary and Cretaceous basins with saltstructures analogous to those of the Gulfof Mexico. Further information can beobtained from the Canada-Nova ScotiaOffshore Petroleum Board’s Internet site,http://www.cnsopb.ns.ca. TheGeological Survey of Canada’s BASINdatabase,http://agcwww.bio.ns.ca/BASIN,contains offshore geological andgeophysical information but requiressubscription for access to specific andcomprehensive data and interpretations.

On the basis of data available through theend of 1983, the Geological Survey ofCanada (Wade and others, 1989) estimatedthe total resource potential of the ScotianBasin to be 18.1 Tcf gas, 366.1 MMBblscondensate, and 707.6 MM Bbls oil. Thisestimate does not include the LauentianSubbasin of the Scotian Basin, for whichMacLean and Wade (1992) have morerecently estimated 8 to 9 trillion cubic feetof gas and 600 to 700 million barrels ofoil. The Canadian government has notassessed the petroleum resources of theEast Georges Bank Basin, the FundyBasin, or the Maritimes and SydneyBasins.

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BIOSTRATIGRAPHY

The paleontological staff of the AtlanticOCS Region examined well cuttings fromfive of the eight Georges Bank explorationwells. The staff used foraminifera,calcareous nannofossils, palynomorphs,and dinocysts to identify biostratigraphicages. Cutting samples were supplementedby core examination, where possible. Biostratigraphic interpretation generallyfollowed Canadian workers’ adaptation ofTethyan practice (e.g., Bujak andWilliams, 1977; Woollam and Riding,1983; Riding, 1984, Davies, 1985). European stages, rather than formationnames, were used for the Georges Bankbiostratigraphic framework. In addition,the staff identified depositionalpaleoenvironments and, for some wells,unconformities and depositional hiatuses,on the basis of missing stages.

The MMS Atlantic paleontologists facedseveral difficulties. The Mesozoic sectionis thoroughly oxidized and reworked,containing many disconformities. Older,eroded and recycled microfossils that werereincorporated into younger sediments hadto be recognized in order to avoid datingan interval as older than it is. Upholemicrofossils, caved from higher in thewell, had to be recognized in order toavoid dating an interval as too young. Other difficulties include documentationof guide fossils. During the 1980's, thebiostratigraphy of the Atlantic margin wasnot well established, compared with othermore thoroughly studied basins. InGeorges Bank wells, diagnostic fossilsbecome sparse with increasing well depth;paleontologically barren sections extend

for hundreds and even thousands of feet. The sparseness is partly explained by thedeltaic and shallow, marginal-marinecharacter of the pre-Late CretaceousMesozoic section. In general, these are notgood environments for the production andpreservation of marine microfossils. Evaporite intervals also tend to be devoidof fossils.

Altogether, the biostratigraphic portions ofthe well reports for the eight industry wellsand the two COST wells should beregarded as subject to increasing error withgreater well depth. Only four wellspenetrated identified Lower Jurassic andolder rocks. The depth of this sectionranges from 11,190 feet (Mobil LC Block312 No. 1) to 17,000 feet (Shell LC Block410 No. 1R). Generally, stratigraphicunits and their depths should be relativelyconsistent among closely spaced wells in alittle-deformed basin. However, amongGeorges Bank wells, apparentinconsistencies between wellbiostratigraphic “tops” become greaterwith increasing well depth.

The greatest disagreements are betweenanalyses done by different groups ofpaleontologists. The COST G-1and G-2and Conoco LC Block 145 No.1 wellswere done by InternationalBiostratigraphers, Inc., the Mobil LCBlock 273 No.1 and Shell LC Block 357No.1 by the operating oil companies, andthe remaining five wells by the MMSAtlantic office paleontological staff.The paleontological staff of the AtlanticOCS Region office initially examined onlywell-cutting samples from the Exxon LCBlock 133 No. 1 well in 1982. Based on

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dinoflagellate cysts, they assigned EarlyJurassic ages to strata in the deepestportion of the well. Subsequently, theoperator submitted splits from aconventional drill core (12,258 to 12,326feet). After a restudy, the staff concludedthat the core samples are Middle Jurassic(Bajocian) in age and that all deepercutting samples represent reworkedsediments that incorporate geologicallyolder, redeposited dinocysts.

A further consequence of the inherentdifficulties and the inconsistentbiostratigraphic interpretation among thepaleontologists from differentorganizations is that the eight burialhistory diagrams for the industry wellshave dissimilar profiles.

THERMAL MATURITY

Within Georges Bank Basin, rocks arethermally mature for oil generation atabout 8,000 feet, for wet gas at about17,000 feet, and for dry gas at about21,000 feet. However, rocks at all welldepths are organically lean, and kerogensare mixed Type II and Type III, becomingmore Type III rich with increasing depth.

Geothermal gradients for the 10 GeorgesBank wells, based on uncorrectedbottomhole logging temperatures, rangefrom 1.06 oF/100 ft (Conoco LC Block145 No. 1) to 1.34 oF/100 ft (Cost G-2)and average 1.26 oF/100 ft. These resultsare about the same as for wells on theCanadian Scotian Shelf (~1.2 oF/100 ft), tothe northeast, and in Baltimore CanyonTrough (~1.2 oF/100 ft), to the southwest,and are higher than for Southeast Georgia

Embayment (~0.9 oF/100 ft), farthersouthwest (Amato and Bebout, 1980).

In the 1970’s and 1980’s the Atlantic OCSRegion Resource Evaluation staff used thethermal alteration index (TAI) of Staplin(1969) to estimate sedimentary thermalmaturity for petroleum generation. Theindex uses alteration colors of organicmaterial in transmitted light as indicatorsof thermal maturity. In the TAI numericalindex, a value of 2.6 (Jones and Edison,1978) indicates borderline maturity forgenerating oil, and values of 3.1 to 3.5indicate the range for production ofcondensate and wet gas. In seven of theeight Georges Bank exploratory wells forwhich TAI analyses are available, thedepth to borderline thermal maturityranges from 9,450 (Mobil LC Block 273No.1 well) to 13,300 feet (Shell LC Block410 No.1R) and averages 11,139 feet. Analyses for five of the wells indicatedepths of 12,450 to 13,950 feet for fullymature TAI values of 2.9-3.1.

The service companies that providedgeochemical analyses for the COST G-2well obtained conflicting results. GeoChem Laboratories, Inc. did the mostextensive TAI analysis and did not findmature alteration colors in any wellsamples (TD 21,874 ft). CoreLaboratories, Inc., reported TAI valuessufficient for oil generation between 8,500and 12,300 feet; they believed that deepersamples were contaminated. M.A. Smith(1980) states that alteration colors aremature (orange-brown) near TD of thewell.

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Vitrinite reflectance data are available foronly 4 of the 10 wells, and they indicatethreshold maturity at shallower depthsthan indicated by TAI. Vitrinitereflectance is based on the reflectivity (Ro)of polished sedimentary vitrinite grains. Avalue of 0.6 percent indicates borderlinethermal maturity for oil generation,whereas 1.0 to 1.5 percent indicates thetime-temperature range for production ofcondensate and wet gas. Vitrinitereflectance values in excess of 2 percentare in the dry gas generation range. Threeof the four Georges Bank wells for whichthere are vitrinite reflectance data, COSTG-1, Mobil LC Block 312 No.1, and ShellLC Block 410 No.1R, have thresholdmaturity values at depths of 6,500 to 9,000feet. In the fourth well, the COST G-2,Ro increases from 0.5 to 1.04 percent(immature to fully mature) at 8,769 feet. Averaging the G-2 result with that of theother three wells produces a depth to theonset of thermal maturity of 8,167 feet. All four wells have peak-generation Rovalues of about 1.0 percent at depths of8,769 to 13,000 feet.

The thermal color index (TCI), developedby Texaco, Inc. in the mid-1980’s, isanother method for quantifying thermalmaturity. Its developers claim superioraccuracy, compared with TAI, becauseTCI is based on spectral analysis oftransmitted light from amorphouskerogens, rather than an operator’sdeterminations of color from a variety ofkerogen types (van Gijzel, 1990). TCI isalso supposed to be superior to vitrinitereflectance analysis because amorphouskerogens are more widely distributed thanvitrinite in sedimentary rocks. TCI has not

been widely accepted by most geochemicallaboratories, which continue to usevitrinite reflectance.

In an effort to resolve the contradictoryCOST G-2 thermal maturity data, Texacoapplied the TCI technique to the well’skerogen slides. Stated in terms of vitrinitereflectance equivalence, the oil window(Ro=.65 percent) begins at 7,750 feet, wetgas (Ro=1.35 percent) begins at 17,000feet, and dry gas (Ro=2.0 percent) beginsat 21,000 feet (Smith and van Gijzel,1990; van Gijzel, 1990).

Petroleum geochemical techniques haveevolved since the Georges Bank wellswere drilled, and we believe that the TCImaturity data, supported by vitrinitereflectance, are more reliable than the TAIanalyses done twenty years ago. Becausethe 10 wells are closely spaced in a little-deformed subbasin, we also believe thatthe COST G-2 TCI data best represent thethermal maturity of the subbasin.

A burial history diagram for the COSTG-2 well, generated using Plate RiverAssociates’ BasinMod ® software, isshown in figure 5. In this diagram, thepost-rift event is the uplift, erosion, andhiatus associated with the post-riftunconformity (Schlee and Klitgord, 1988).The magnitude of the uplift and durationof the event are strictly diagrammatic. Thepetroleum generation maturity windowsare based on TCI data, expressed asvitrinite reflectance values, and thecalculated present-day heat flow(57 mW/m2). The heat-flow value is basedon corrected well-bore temperature datafrom the COST G-2 well (Amato and

Early Mature oil0.6 to 0.75 %Ro

Mid Mature oil0.75 to 1.0 %Ro

Late Mature oil1.0 to 1.3 %Ro




Main Gas Generation1.3 to 2.6 %Ro




Main Gas Generation1.3 to 2.6 %Ro

Age (my)050100150200250

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Oxfordian

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Bathonian-Pliensbachian

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Figure 5. Burial history diagram for the COST G-2 well, constructed with Platte River Associates' BasinMod software. Tops of Callovian and younger stages, taken

from U.S. Geological Survey Open-File Report 80-269, are based on MMS Atlantic OCS Region paleontological analysis. Tops of Bathonian (?) and older units from U.S. Geological Survey Circular 861 are based on seismic stratigraphy. The Mesozoic time scale is after Gradstein and others, 1995, and the Cenozoic times scale is after Berggren and others, 1995. The post-rift event consists of the uplift, erosion, and hiatus associated with the post-rift unconformity. Magnitude of the uplift and duration of the event are strictly diagrammatic. Petroleum maturity windows are based on TCI kerogen analysis expressed as vitrinite reflectance (R ) values.o

R

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Simonis, 1980). According to thismodel, petroleum generation, givenadequate source rock, began in about theMiddle Jurassic Epoch at well depths of12,000 feet in the COST G-2 well.

Figure 6 is a BasinMod® diagramshowing corrected borehole temperatures,a temperature profile, measured vitrinitevalues, and a regression fit of thermalmaturity to depth. In the well, earlymaturity for oil generation (Ro =0.6percent) begins in Upper Jurassic rocksnear 8,500 feet and main gas generation(Ro=1.35 percent) begins in MiddleJurassic rocks near 16,500 feet. Thesedepths are within 750 and 500 feet,respectively, of agreement with Texaco’sTCI data.

ORGANIC RICHNESS

Sedimentary units encountered by drillingin Georges Bank Basin are organicallylean, according to total organic carbon(TOC) analyses from 7 of the 10 wells. Most samples have less than 1 percentTOC. Only one sample from the 7 wellshas a value of more than 3 percent. Datafrom all but one well show organicrichness decreasing with depth. Theexception is the Tenneco LC Block 187No. 1 well, which shows as much as 1.65percent TOC in Upper Triassic units deepin the well. In general, most Cretaceoussamples are between 0.25 and 1.5 percent;most Upper and Middle Jurassic samplesare between 0.2 and 0.6 percent; mostLower Jurassic samples are between0.1and 0.3 percent; and most Triassicsamples are less than 0.2 percent. Carbonate and evaporite lithologies are

associated with low organic carbonabundance. In summary, the source rockpotential in the currently drilled portion ofGeorges Bank Basin at sufficient depthsfor thermal maturity, 8,000 to nearly22,000 feet (the deepest drilling), is poor.

ORGANIC MATTER TYPES

For petroleum exploration, the organicallylean section encountered in Georges BankBasin diminishes the relevance of organicmatter type analysis. However, MMS andindustry performed many kerogen analyseson well cuttings and cores in the 1980’s.

Kerogen is disseminated sedimentaryorganic matter that has not been convertedto petroleum. In assessing source-rockpotential, the Atlantic OCS Office staffclassified kerogen as algal-amorphous,herbaceous, woody, or coaly, using amicroscope and transmitted light. Thestaff examined samples from six of theeight industry wells and service companiesexamined the two COST wells. In the sixwells, the highest abundance of algal-amorphous kerogens is reported to be inthe uppermost 5,000 to 8,000 feet, rangingto over 30 percent of total kerogens. Below about 10,000 feet, algal-amorphousabundances generally range from zero to5 percent. Herbaceous kerogens aregenerally between 20 and 30 percent, andwoody kerogens are generally between 20and 40 percent at all well depths. Coalymatter generally ranges from 20 to60 percent and increases with depth.

These relationships are also evident in theCOST G-1 visual kerogen data; however,the service company (GeoChem) analyst

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Figure 6. BasinMod diagram for the COST G-2 well displaying petroleum maturity windows, borehole temperatures, temperature profile, vitrinite reflectance values, and thermal maturity profile. The heavy red crosses with error bars are corrected borehole temperatures taken from well logs. The dashed red graph line represents the temperature profile calculated using the model assumptions. Black crosses with error bars are TCI kerogen maturity measurements expressed as R values. The dashed black line is a regression fit to the TCIo data. The solid black graph line represents thermal maturity as modeled by BasinMod . Petroleum maturity windows are based on TCI.

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Thermal Maturity%R RegressionoSubsurface TemperatureEarly Mature oil0.6 to 0.75 %RoMid Mature oil0.75 to 1.0 %RoLate Mature oil1.0 to 1.3 %Ro

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Figure 6. BasinMod diagram for the COST G-2 well displaying petroleum maturity windows, borehole temperatures, temperature profile, vitrinite reflectance values, and thermal maturity profile. The heavy red crosses with error bars are corrected borehole temperatures taken from well logs. The dashed red graph line represents the temperature profile calculated using the model assumptions. Black crosses with error bars are TCI kerogen maturity measurements expressed as R values. The dashed black line is a regression fit to the TCIo data. The solid black graph line represents thermal maturity as modeled by BasinMod . Petroleum maturity windows are based on TCI.

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Thermal Maturity%R RegressionoSubsurface TemperatureEarly Mature oil0.6 to 0.75 %RoMid Mature oil0.75 to 1.0 %RoLate Mature oil1.0 to 1.3 %RoMain Gas Generation1.3 to 2.6 %Ro%R oBorehole Temperature

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recognized a higher proportion of algal-amorphous kerogen throughout this well,compared with the industry wells. Algal-amorphous kerogens are mostly in the 20to 40 percent range down to 6,000 feet andin the zero to 30 percent range from 6,000feet to total depth (Smith and Shaw, 1980;Miller and others, 1982). In the COSTG-2 well, the kerogen analyses furnishedby two service companies arecontradictory and not consistent with theother wells (Smith, 1980, Miller andothers, 1982). GeoChem Laboratoriesreported that in the G-2 well, algal-amorphous, herbaceous, woody, and coalyrelative abundances are fairly consistent atall depths, with proportions of about 40,15, 20, and 25 percent, respectively. CoreLaboratories, Inc., reported that algal-amorphous kerogens are nearly absent inthe well but that inertinite (coaly) is thedominant kerogen type throughout,especially below 8,500 feet, accounting foras much as 90 percent of the organicmatter.

The lack of consistency among kerogenstudies is likely caused by variation inanalyst assumptions and techniques. Differences include deciding what materialshould be ignored because it is caved fromhigher in the drill hole, recycled, andredeposited from older strata, orintroduced from the platform in drillingthe well.

M. A. Smith (1995) reports a more recentCOST G-2 visual kerogen analysis doneby Geo-Strat, Inc., to resolve thesecontradictions. In this restudy, the analystused 18 organic matter types, rather thanthe 4 types previously employed.

However, most of the recognized kerogenwas algae and amorphous algal debris,plant tissue, and amorphous herbaceousdebris, vitrinite (wood), and inertinite(coal). That is, these organic matter typescorrelate well with the previously usedfour types, algal-amorphous, herbaceous,woody, and coaly. The practicaldifference is that, previously, algal-amorphous was one category, and now aportion of that is classed as herbaceousmatter. Consequently, the Geo-Strat studyidentifies only 4 to 8 percent of totalkerogens as algal in all but two wellsamples. Total herbaceous matter(amorphous herbaceous plus plant tissue)amounts to about half of total kerogensdown to 11,500 feet; 20 percent to 15,500feet, 70 percent to 19,500 feet, and 35 to60 percent to total depth. Woody kerogensare about 20 percent to 11,500 feet,35 percent to 15,500 feet, and 10 to 20percent to total depth. Coaly matterincreases from about 5 percent at shallowdepths to about 20 percent near total depth.

Among the COST G-2 kerogen analysesdone by different parties, Core Labs’analysis appears to be so different that itcan be rejected. GeoChem’s and Geo-Strat’s results are similar, allowing fordifferent definitions of algal andherbaceous matter. However, Geo-Strat’srelative abundances are more variablethroughout the well.

Thermal pyrolysis and moleculargeochemical analysis data relevant torelative kerogen abundance are availablefor the COST G-1 and G-2 and the ExxonLC Block 133 No. 1 and the Tenneco LCBlock 187 No. 1 wells. Kerogen relative

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abundance is reflected in the hydrogenindex (HI=S2/TOC) and the atomichydrogen-to-carbon ratio (H/C). Fromhigher to lower HI and H/C, the order ofkerogen types is algal, amorphous,herbaceous, woody, and coaly. Hydrogenindex values of less than 200 andhydrogen-to-carbon ratios less than 1.0suggest that woody and coaly organicmatter equals or exceeds herbaceous andalgal-amorphous matter and that theprimary expelled hydrocarbon will be gas.For Exxon LC Block 133 No. 1 wellsamples, the HI ranged from 0 to 143 andfor Tenneco LC Block 187 No. 1 wellsamples, the H/C ranged from 0.11 to0.76, suggesting mixed algal-herbaceousand woody-coaly kerogens, with the lattergenerally in greater abundance. The 50 HIvalues of the Exxon well are extremelyvariable throughout; however, in general,they decrease in magnitude with depth,indicating decreasing algal-amorphous andincreasing woody and coaly abundancesseen in the optical kerogen analysis. Onlya descriptive summary of the H/C ratios ofthe Tenneco well is available, and there isno statement about whether the ratiochanges with depth.

We believe that the Geo-Strat kerogenstudies on the COST G-2 well (Smith,1995) are more reliable than the opticalkerogen analyses of this well described inthe 1980 U. S. Geological Survey Open-File Report 80-269 and the 1982 U. S.Geological Survey Circular 861. Further,we believe that the Geo-Strat datarepresent the basin better than the eightindustry well kerogen studies done in theearly 1980’s by the MMS Atlantic OCS

Region office and contained in theaccompanying well reports.

The final step of Geo-Strat’s kerogenprocedure is to combine the data for eachsample interval and assign an organicmatter index (OMI) number. The OMIvalues are then plotted against well depthto provide a profile of oil and gasproneness for the stratigraphic column. The index ranges from 1, strongly oilprone, to 8, strongly gas prone. The scaleis also divided into Type I, Type II, TypeII-Type III mix, and Type III organicmatter fields. For the COST G-2 well(figure 7), most samples are between 4.35and 5.25, which is within the Type II-TypeIII mixed field, indicating the probabilityof both oil and gas. However, indexvalues increase with depth, indicating thehigher likelihood of natural gas deep in thewell.

FUTURE EXPLORATION

It is nearly 18 years since the lastpetroleum exploration well was drilled onGeorges Bank, and the area is currentlyunder a leasing moratorium. However, inrecent years companies have made 24 gas-condensate discoveries in the CanadianScotian Basin, to the northeast, and sixfields are being developed. A third cycleof exploration activity is underway alongthe eastern Canadian margin that includespreviously unexplored areas and plays.

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Figure 7. Organic matter index (OMI) for the COST G-2 well. Index values are calculated from kerogen type analysis, which recognizes 18 kinds of kerogen. Data from Schwab and others, 1990.

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When petroleum exploration does resumein Georges Bank Basin, new, state-of-the-art seismic data acquisition and processingwill have high priority. The goal will bebetter resolution of deep structures (belowthree seconds, two-way travel time). Although seismic data from the 1970’s and1980’s show deep features, they aredifficult to interpret owing to poorresolution and spatial distortion anddisplacement. The Georges Bankstratigraphic section is thinner than that ofBaltimore Canyon Trough or the ScotianBasin. Record lengths of six to sevenseconds, two-way-time, will adequatelyimage this Upper and Middle Jurassic partof the section, as well as the underlyingTriassic-Early Jurassic rift basins. Withmodern seismic data, good resolution willbe achievable for the entire sedimentarysection.

Well data suggest that identified organicsource rock is the major componentmissing from the Georges Bankhydrocarbon system. Untested and poorlytested facies, including lacustrine shalesand marls of Early Mesozoic rift basins,relict Upper Paleozoic basins, and theCretaceous paleo-continental slope, mayprovide source rocks capable of chargingthe petroleum system. Deeper drillingmay also be effective in Georges BankBasin. Most of the gas discoveries nearSable Island in the Scotian Basin areassociated with overpressure, generally atabout 13,500 feet. Severely overpressuredgas was encountered, but not tested, at17,807 feet in the Texaco Hudson CanyonBlock 642 No. 1 well in Baltimore Canyon

Trough (Amato and Bielak, 1990). Deeperdrilling in Georges Bank Basin, likelybelow 20,000 feet, may also findoverpressured gas. Gas-condensate or drygas is the most likely hydrocarbon at thesedepths, with temperatures in excess of300 oF.

ACKNOWLEDGMENTS

We thank David E. Brown, SeniorGeologist at the Canada-Nova ScotiaOffshore Petroleum Board, for reviewingthe portions of this report that discuss theScotian Shelf and petroleum exploration,development, and production offshorefrom Nova Scotia. Mr. Brown alsocontributed up-to-date information.

MMS, Gulf of Mexico OCS Regionpersonnel who contributed to the projectinclude Michael Smith, who contributeddata and interpretations from petroleumgeochemical work he had done in previousyears with Texaco and Geo-Strat, Inc. Paul Post helped us with the Platte RiverAssociates’ BASINMOD® software. Dr. Smith and Mr. Post also reviewed thismanuscript. The late Gerald Marchesedrafted the illustrations.

Those within MMS who contributed to theoverall Georges Bank well report projectinclude Michael Smith (petroleumgeochemistry), Gary Watkins (wellvelocity data), Harold Fitzgibbon (drillingoperations), Gerald Marchese (graphics),Linda Wallace (graphics), and RussellLabadens (graphics).

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REFERENCES

Amato, R.V., and J.W. Bebout (eds.), 1980, Geologic and Operational Summary, COST No. G-1 Well, GeorgesBank Area, North Atlantic OCS: U. S. Geological Survey Open-File Report 80-268, 112 p.

Amato, R.V., and L.E. Bielak (eds.), 1990, Texaco Hudson Canyon 642-1 Well; Minerals Management ServiceOCS Report MMS 89-0027, 56 p.

Amato, R.V. and E.K. Simonis, (eds.), 1980, Geologic and Operational Summary, COST No. G-2 Well,Georges Bank Area, North Atlantic OCS: U. S. Geological Survey Open-File Report 80-269, 116 p.

Berggren, W.A., D.V. Kent, C.C. Swisher III, and M.P. Aubry, 1995, A revised Cenozoic geochronology andchronostratigraphy; in Geochronology Time Scales and Global Stratigraphic Correlation, SEPMSpecial Publication no. 54, p. 129-212.

Bujak, J. P, and G. L. Williams, 1977, Jurassic palynostratigraphy of offshore eastern Canada, in F. M. Swain,(ed.), Stratigraphic Micropaleontology of Atlantic Basin and Borderlands: New York, ElsevierScientific Publishing Co., p. 321-339.

Davies, E. H., 1985, The miospore and dinoflagellate cyst oppel-zonation of the Lias of Portugal: Palynology, v.9, p. 105-132.

Gradstein, F.M., F.P.Achterberg, J.G. Ogg, J.Hardenbol, P. van Veen, and Z. Huang, 1995, A Triassic, Jurassic,and Cretaceous time scale; in Geochronology Time Scales and Stratigraphic Correlation, SEPMSpecial Publication no. 54, p. 95-126.

Jones, R. W. and T. A. Edison, 1978, Microscopic observations of kerogen related to geochemical parameterswith emphasis on thermal maturation, in D. F Oltz (ed.), Geochemistry: Low TemperatureMetamorphism of Kerogen and Clay Minerals: Society of Economic Paleontologists and Mineralogists,Pacific Section, Annual Meeting, Los Angeles, p. 1-12.

MacLean, B.C., and J.A. Wade, 1992, Petroleum geology of the continental margin south of the islands of St.Pierre and Miquelon, offshore eastern Canada: Bulletin of Canadian Petroleum Geology, v. 40, no. 3,p. 222-253.

Miller, R. E., H. E. Lerch, G. E. Claypool, M. A. Smith, D. K. Owings, D. T. Lignon, and S. B. Eisner, 1982,Organic geochemistry of the Georges Bank basin COST Nos. G-1 and G-2 wells, in P. A. Scholle andC. R. Wenkam (eds.), Geological Studies of the COST Nos. G-1 and G-2 Wells, Unites States NorthAtlantic Outer Continental Shelf: U. S. Geological Survey Circular 861, p. 105-142.

Riding, J.B., 1984, Dinoflagellate cyst range-top biostratigraphy of the uppermost Triassic to lowermostCretaceous of northwest Europe: Palynology, v.8, p. 195-210.

Schlee, J.S. and K.D. Klitgord, 1988, Georges Bank Basin: a regional synthesis; in R.E. Sheridan and J.A. Grow(eds.), The Geology of North America, vol. I-2, The Atlantic Continental Margin, Geological Societyof America, p. 243-268.

Scholle, P. A. and C. R. Wenkam (eds.), 1982, Geological Studies of the COST Nos. G-1 and G-2 Wells,United States North Atlantic Outer Continental Shelf: U.S. Geological Survey Circular 861, 193 p.

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Schwab, K.W., P. van Gijzel, and M.A. Smith, 1990, Kerogen evolution and microscopy workshop short course,International Symposium on Organic Petrology, Zeist, the Netherlands, January 10 and 11, 1990(unpublished).

Smith, M.A., 1980, Geochemical analysis, in R.V. Amato and E.K. Simonis (eds.), Geologic and OperationalSummary, COST No. G-2 Well, Georges Bank Area, North Atlantic OCS: U. S. Geological SurveyOpen-File Report 80-269, p. 77-99.

Smith, M. A., 1995, Assessment of U.S. Atlantic hydrocarbon resources using new geochemical technology:Geological Society of America, Abstracts with programs, 1995 Annual Meeting, New Orleans, LA.

Smith, M.A. and D.R. Shaw, 1980, Geochemical analysis, in Amato, R. V. and J. W. Bebout (eds.), Geologicand Operational Summary, COST No. G-1 well, Georges Bank Area, North Atlantic OCS: U. S.Geological Survey Open-File Report 80-268, p. 81-94.

Smith, M.A., and P. van Gijzel, 1990, New perspectives on the depositional and thermal history of GeorgesBank in W.J.J. Fermont and J.W. Weegink (eds.), Proceedings, International Symposium on OrganicPetrology, Zeist, the Netherlands, p. 49-64.

Staplin, F.L., 1969, Sedimentary organic matter, organic metamorphism, and oil and gas occurrence: Bulletin ofCanadian Petroleum Geology, v. 17, no. 1, p. 47-66.

Van Gijzel, P., 1990, Transmittance colour index (TCI) of amorphous organic matter: a new thermal maturityindicator for hydrocarbon source rocks, and its correlation with mean vitrinite reflectance and thermalalteration index (TAI); in W.J.J. Fermont and J.W. Weegink, eds., Proceedings, InternationalSymposium on Organic Petrology, Zeist, the Netherlands.

Wade, J.A., G.R. Campbell, R.M. Proctor, and G.C. Taylor, 1989, Petroleum resources of the Scotian Shelf:Geological Survey of Canada Paper 88-19.

Woollam, R. and J.B. Riding, 1983, Dinoflagellate cyst zonation of the English Jurassic: Institute of GeologicalSciences Report, v. 83, No. 2, p. 1.

IllustrationsFigure 1Figure 2Figure 3Figure 4Figure 5Figure 6Figure 7

Table 1Leasing HistoryExploration HistoryBiostratigraphyThermal MaturityOrganic RichnessOrganic Matter TypesFuture ExplorationAcknowledgmentsReferences

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