Contract No. 60122058 of March 31, 2004 Final Report ... · Final Report (Revised) Submitted to Paul J. Harvey Project Coordinator, Cape Breton Project Nova Scotia Department of Energy

Contract Number: 60122058 of March 31, 2004: Global Geoenergy Research Ltd.” Final Report on the “Evaluation of Petroleum Potential…Cape Breton Island, Offshore Nova Scotia.”

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EVALUATION OF PETROLEUM POTENTIAL OF THE DEVONIAN-CARBONIFEROUS ROCKS FROM CAPE

BRETON ISLAND, ONSHORE NOVA SCOTIA

Contract No. 60122058 of March 31, 2004 Final Report (Revised) Submitted to

Paul J. Harvey Project Coordinator, Cape Breton Project

Nova Scotia Department of Energy Bank of Montreal Building

5151 George Street, Suite 400 Halifax, Nova Scotia

B3J 3P7

By

Dr. P. K. Mukhopadhyay (Muki) Global Geoenergy Research Ltd. 1657 Barrington Street, Suite 427

(P.O. Box 9469, Station A) Halifax, Nova Scotia B3J 2A1 (B3K 5S3)

Including a partial contribution on Geology, Structural Interpretation, and History of Petroleum Exploration

from W. G. Shaw and Associates

65 Beech Hill Road Antigonish, Nova Scotia B2G 2P9

(including Geological Maps)

October 26, 2004


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EXECUTIVE SUMMARY The final contract report has established the first documentation of the Oil and Gas Potential of the Devonian-Carboniferous sediments from selected subbasins of Cape Breton Island: Mabou-Ainslie, Bras d’Or, Loch Lomond, and the Sydney Basin. The current report is considered the Phase I study of Petroleum System Risk Assessment (Mukhopadhyay et al., 2003). This program has been achieved by utilizing and assessing selected geological and geochemical analytical data (both source and reservoir rocks) generated during the current contract and documentation from other analytical data of Carboniferous sediments from Cape Breton Island by earlier researchers. As the current report represents a synthesis of the hydrocarbon habitat of the selected subbasins of Cape Breton island, the executive summary will include three sections for each individual subbasin: (A) geological interpretation (seismic and structural interpretation, and play type definitions); (B) brief evaluation of the petroleum systems (organic richness, source rock analysis, maturation, possible timing of hydrocarbon expulsion, and genesis of the oil families already present as seepages or stains); and finally (C) a short appraisal of the oil and gas prospects. The brief appraisal of oil and gas potential from each subbasin will delineate potential areas for future oil and gas exploration strategies within Cape Breton Island. WESTERN CAPE BRETON SUBBASINS Mabou-Ainslie Subbasin Geological Appraisal

The general structural configuration of the Mabou-Ainslie subbasin is dominated by low-angle thrusts associated with subbasin-bounding, northeast-trending, strike-slip and oblique fault systems, possible salt structures, and elevated basement blocks (Durling et al. 1995a). Extensional and transgressional stresses have resulted in a somewhat complex structural configuration in this subbasin.


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Comparison of the Strathlorne Formation within the Ainslie

Depocentre with the petroleum productive Albert Formation from the New Brunswick suggests that similar petroleum charged play type #1 and play type #2 could be dominant within the Horton Group. The play type #1 represents the sandstone reservoirs within the Strathlorne and Ainslie formations that occur within anticlinal structures forming combination, stratigraphic-structural traps (similar to recently-discovered McCully Gas Field, in southeast New Brunswick), whereas play type #2 represents the sandstone reservoirs within the Strathlorne and Ainslie formations that lie beneath gently dipping reverse faults.

In the Windsor Group, specific play type #5 (carbonate bioherm

reservoirs; Figure 10) and play type #6 (up-dip truncation of carbonate reservoirs against evaporate) could be present within the deeper part of the Mabou-Ainslie Subbasin. However, Windsor Group play types in this area may not be very significant as a large stratigraphic gap exists within the Windsor Group, which is caused by a major, extensional, bedding-parallel, detachment fault.

Geochemical Appraisal

Lower Carboniferous sediments of the Horton Group from the northern part of this subbasin have potential organic-rich oil-prone source rocks, which still lie within the Oil Window. On the other hand, similar sediments from the southern part of the Mabou-Ainslie Subbasin have been associated with major folding and thrusting and have only minor gas prone source rocks. These sediments mostly lie within the late phase of condensate generation.

The upper Carboniferous Mabou and Cumberland Group sediments are prolific gas and condensate prone source rocks that lie within the Oil Window.

The various oil seeps and oil stains from Lake Ainslie and surrounding areas indicate that they are derived from the lacustrine source rocks of the Horton Group (possibly from the Strathlorne Formation). Marine carbonate source rocks from the Windsor Group (especially the Macumber Formation) did not contribute much to the hydrocarbons of these oil seeps and stains (this report; Fowler et al., 1994).


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No oil stains could be detected in any of the core samples from the southern part of Mabou-Ainslie Subbasin.

Previous research on 1D petroleum system modeling from other subbasins on mainland Nova Scotia by the author suggests that the expulsion of crude oil from source rocks of the Horton Group occurs within 320-315 Ma and around 300-280 Ma for the Windsor Group. Source rocks from both groups expelled hydrocarbon gases around 280-270 Ma.

Oil and Gas Potential

Most of the petroleum prospects in the Lower Carboniferous play types of the Mabou-Ainslie subbasin are restricted to the Horton Group. Both play types # 1 and #2 of the Horton Group may be represented by the oil stained sandstone reservoirs surrounding the Lake Ainslie region. Most of the oil seeps and stains in that region are present within uplifted and structurally disturbed shallow reservoirs, which are highly porous (>10%) and permeable (>5 mD) and biodegraded.

Most oil seeps within the Lake Ainslie region are genetically related to lacustrine Strathlorne Formation source rocks similar to the Albert Formation in New Brunswick.

Global Geoenergy Research Limited predicts that the deeper (500-1500m) Horton Group reservoirs within the north and northeastern part of the Ainslie depocentre are considered to be one of the major potential targets within Cape Breton Island for future liquid (crude oil and condensate) hydrocarbon discoveries. This prediction is based on:

• the presence of numerous oil seepages and oil-prone source rocks,

• overall thermal maturity, • abundant porous and permeable (>15 mD) sandstones within

both the Ainslie and Strathlorne formations of the Horton Group,

• the timing of crude oil expulsion from the Lower and Middle Horton Group source rocks in relation to the timing of the reservoir compaction of the Horton Group sediments, and

• the sealing efficiency of the Upper Horton Group shale or Windsor Group carbonate.

• possible presence of deep basinal facies within the east and northeastern parts of Lake Ainslie.

These reservoirs will be associated with play types #1 and #2, which could be similar to the productive Carboniferous Stoney Creek Field in New Brunswick. The Stoney Creek oil and gas field


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has produced 800 thousand barrels of oil and 30 BCF of natural gas between 1910 and 1991. The pay zones occur with stratigraphic-structural traps associated with upthrown three-way closures.

The lack of oil stains or gas shows in any of the previously drilled

wells, the presence of highly disturbed structures, the absence of potential source rocks, and elevated thermal maturity within the southern part of the Mabou-Ainslie subbasin may indicate a low oil and gas potential for the Lower Carboniferous sediments.

The channel sandstones from the Upper Carboniferous Cumberland

Group (similar to Boss Point Formation) (play type undefined due to lack of data) may have a major potential for discovering gas and condensate in the southern part of the Lake Mabou-Ainslie subbasin. However, current sparse seismic data coverage did not show any promising three or four way closures.

CENTRAL CAPE BRETON SUBBASINS Bras D’Or Subbasin Geological Appraisal

The Bras d’Or Subbasin is an oval shaped, northeast trending synclines that has been affected by syn- and post-Carboniferous folding and faulting. In this area, Windsor Group strata are in direct contact with underlying basement rocks with an angular unconformity. Horton Group strata are not being penetrated in any of the wells although are present as a thin unit. Systematic interpretation of play types requires new 2D seismic lines in this region.

Within the Macumber Formation of the Lower Windsor Group and

other carbonates of the Middle Windsor Group, bioherm lithofacies forming play type #5 and play type #9 may be identified (Figure 10). The reservoirs in play types #5 and #9 may have developed along basin margins and on subtidal paleotopographic highs.

Some of the oil stained and crude oil bearing reservoirs in the

Jubilee (sample numbers 1, 2, 3, and 5; Table 2), Malagawatch (sample numbers 28 and 29; Table 2) and Bras d’Or (Bras-d’Or #1 and #2 wells; no samples taken) may have close affinities with play types #5 and #9 (Figure 10) within the Windsor Group. However, the low porosity and permeability data of the selected analyzed


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reservoirs indicates the need for systematic study on the physical analysis of the various reservoir rocks.

Geochemical Appraisal

Most of the Windsor sediments (especially the Macumber Formation in the Jubilee area) are organic rich, have crude oil potential, and lie within the Oil Window. The deeper mature sediments from this group have gas and condensate potential.

Several oil stain and crude oil samples (one crude oil and eight stained source or reservoirs rocks; Figures 18, 23a, 23b, 23c, 23d, 23e, 27a, and 27b) from the Windsor Group are genetically related to two distinct source rock types:

• the crude oil from the Malagawatch M-9 well and the oil stain within both carbonate reservoir rock (ATG-17-77 well: Mukhopadhyay, 2000) were derived from marine carbonate source rock (possibly from the Macumber Formation). The crude oil shows a maturity of 0.8-1.0% Ro, whereas the oil stain in other reservoir rock is derived from 0.5 to 0.7% Ro.

• Four other oil stained carbonate reservoir and source rocks

from the Windsor Group (reservoir rocks: Malagawatch M-3 well [sample no. 35, Table 2], ATG-34-77 well [sample no. 3, Table 2]; Table 2]); and McIvor Pt #1 well [Mukhopadhyay 2000], and source rock: McIvor Pt #1 well [Mukhopadhyay 2000]) are derived from a mixture of hypersaline marine (Windsor Group) and lacustrine (Horton Group; sample no. 3, Table 2) or terrestrial (Windsor group; sample no. 35 and McIvor Pt #1 well) source rocks. The three reservoir rocks are derived at a maturity of 0.7 to 0.9% Ro and the source rock from the McIver Pt #1 well has a low maturity (<0.6% Ro). Both oil stains from the McIver Pt #1 well are partially biodegraded.


o Most of the petroleum prospects are concentrated within fractured carbonate reservoirs of play type #5 of the Windsor Group (Figure 10). Although the porosity data from the selected bioherm reservoir rocks appears promising, the permeability data of this study indicates that potential oil stained fractured reef (bioherm) reservoirs have not yet been thoroughly studied.


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o The existence of thicker Horton Group (both Ainslie and Strathlorne formations) in the northeastern part of the Jubilee area (northeastern part of Bras d’Or Subbasin) may indicate the presence of both play type #1 within the Horton Group and play type #5 in the Macumber Formation of the Windsor Group. Global Geoenergy Research Limited has predicted this region as one of the most potential areas for a future crude oil discovery.

o The play type #6 (updip truncation of carbonate reservoirs against

salt diapirism or fault) and associated subsalt plays could be significant especially within the Malagawatch-Bras d’Or area. The low maturity of the subsalt play could be of importance within the deeper part of the Bras-d’Or subbasin in discovering medium gravity oil within this subbasin including the Jubilee area.

o The implication of the following petroleum system parameters has

projected a prospect of oil within the middle to lower Windsor Group (700m) play type #5 and #6 reservoirs within the Bras-d’Or Subbasin:

Abundance of oil seeps and oil stains within the Windsor Group carbonates in the Bras d’Or subbasin (including the Jubilee area),

Presence of mature oil-prone source rocks, The timing of liquid hydrocarbon expulsion (300 to 280 Ma)

from the Windsor Group is later than the timing of compaction of the Windsor Group reservoirs (~335 to 325Ma; based on earlier 1D modelling),

Possible presence of the bioherm and ramp facies reservoirs within the subsalt plays could be extremely important below 500m.

Loch Lomond Subbasin The petroleum potential of this subbasin could not be evaluated due to absence of seismic data and lack of geological data. However, selected samples have been evaluated by geochemical fingerprinting. This data suggest the following interpretations:

The Windsor group source rocks are organic rich and have both oil and gas potential. On the other hand, Mabou and Cumberland Group source rocks are gas and condensate prone,

Sediments from the Windsor, Mabou, and Cumberland groups lie

within the “Oil Window”, and


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The biomarker analysis of one oil stained carbonate reservoir from

Loch Lomond – 04 well suggests that this oil was derived from a mixture of hypersaline marine carbonate (Windsor Group) and lacustrine (Horton Group) source rocks. The maturity of this oil suggests that it was generated at a maturity level of 0.7 to 0.9% Ro (calculated).

NORTHEASTERN CAPE BRETON SUBBASINS Sydney Basin Geological Appraisal

The Sydney Basin has a prominent northeast structural trend that has been modified by the superposition of an east-trending element in the Pennsylvanian strata of the Morien Group. The Pennsylvanian (Upper Carboniferous) strata within the basin area are folded into broad, open asymmetric synclines and anticlines with an arcuate fold axis. These folds appear to be related to the faulted and folded Mississippian rocks situated on the basement fault blocks.

The structural and play type interpretation of the Sydney Basin

could not be evaluated due to the lack of seismic and other data. Geochemical Appraisal

In the southern and western parts of the Sydney Basin, most of the Windsor Group and Cumberland Group sediments lie within the Oil Window. The Windsor Group sediments are organic-rich and have high potential for crude oil. With the exception of oil shale samples from the Cumberland Group, most of the sediments from this group have gas and condensate potential.

Two analyzed oil stain carbonates from the Windsor Group are genetically related to two distinct source rock types:

o The shallower sample from the Ingonish #1 well suggests that it was derived from a marine carbonate source rock (possibly from the Macumber Formation) at a maturity of 0.5 to 0.7% Ro,

o The other oil stain reservoir rock from the North Sydney F-24 well has suggested that it was derived from a mixture of hypersaline marine carbonate (Windsor Group)


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and terrestrial (possibly from the Mabou Group) source rocks within a maturity of 0.7 to 0.9% Ro.


o Most of the oil and gas prospects within the onshore Sydney Basin are mainly restricted to bioherm play types (possibly play type #5 similar to the central Cape Breton subbasins) of the Windsor Group and channel sandstone reservoirs of the Cumberland Group, which result from a combination of structural-stratigraphic traps. The Horton Group sandstone play type #1 could not be analyzed due to the lack of seismic data. However, play types #1 and #2 could be visualized within the offshore Sydney subbasin from the earlier works of Pascucci et al. (2000).

o Based mainly on the source rock potential and the genesis of oil

stains, the oil potential of the Sydney Basin is restricted to the Windsor Group within the western (east of the Boisdale Inlier; Figure 3b) and in the southern portion of the basin (Glen Morrison; Figure 3b). However, the liquid hydrocarbons in these parts of the basin are expected to be of higher gravity than the Bras d’Or subbasin. The major gas potential of the Cumberland Group is restricted to the northern part of the onshore portion of the Sydney Basin and the northeastern portion of the offshore Sydney Basin.


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1. INTRODUCTION 1.1. CONTRACT: ADMINISTRATIVE ASPECTS Based on the request for quotation (RFQ) from the Public Tenders Office (Nova

Scotia Procurement Branch vendor number 10038515), Global Geoenergy

Research Limited submitted its proposal on February 26, 2004 for the

“Evaluation of Petroleum Potential of the Devonian-Carboniferous rocks from

Cape Breton Island, Onshore Nova Scotia. The proposal was accepted in March

2004 and contract was awarded to Global Geoenergy Research Limited on

March 31, 2004 (No. 60122058).

The contract was initially intended (by the Nova Scotia Department of Energy to

be completed within 12 weeks commencing on April 1, 2004. However, due to

time problems related to the collection of both outcrop (from Western Cape

Breton Island) and core/cuttings samples from the Core Library of the Nova

Scotia Department of Natural Resources at Stellarton, Nova Scotia, the

completion date of the current contract was extended by the Project Coordinator

(Paul Harvey, Nova Scotia Department of Energy) for another six weeks.

As a subcontractor to Global Geoenergy Research Limited and part of the

contract, W. G. Shaw & Associates Limited from Antigonish, Nova Scotia has

provided the following sections of the current report: (i) geological/geophysical

interpretation of the western and central Cape Breton Island (Chapters 3.1, 3.2,

3.3, 3.4, and 3.6; partially modified by PKM), (ii) history of the earlier exploration

activities (Chapter 3.7; partially modified by PKM); and (iii) various geological

maps and cross-sections (Figures 1, 3a, 3b, 4, 5, 6a, 7, 8, 9, and 10). A copy of

the geological report submitted by W. G. Shaw & Associates is enclosed the

folder of this report. Humble Instruments and Services Incorporated from

Humble, Texas, USA have performed geochemical (Rock-Eval pyrolysis, etc) and

analysis of selected source rocks or oil-stained reservoir rocks as a

subcontractor. AGAT Laboratories Inc. from Calgary, Alberta has conducted


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specific physical properties (porosity, permeability, etc) of selected reservoir

rocks.

During the tenure of the project, Dr. P. K. Mukhopadhyay from Global Geoenergy

Research Limited and Billy Shaw from W. G. Shaw and Associates have

attended several high level scientific discussions with the following scientists at

various locations: Bob Boehner, John Calder, Robert Naylor, and Bob Ryan from

the Nova Scotia Department of Natural Resources; Paul Durling from Corridor

Resources; Peter Giles from the Geological Survey of Canada; and Kim Doane,

Paul Harvey, Kris Kendall, and Jack MacDonald from the Nova Scotia

Department of Energy. The topics of discussions in these sessions were mainly

geological/geophysical interpretations and sample selection for various analyses.

According to contract, eight (8) bi-weekly progress reports have been submitted

to the Project Coordinator within the stipulated time intervals. Dr. P. K.

Mukhopadhyay (Muki), President, Global Geoenergy Research Limited has

written the interpretative final report. Accordingly, he has modified the written

contributions on geological and structural interpretations as provided by W. G.

Shaw and Associates Limited. 1.2. BACKGROUND AND OVERVIEW Cape Breton Island, which is a part of the Maritimes Basin in Eastern Canada is

located within the following structural framework (Figures 1, 2, 3a, and 3b:

♦ The Western Newfoundland Paleozoic Basins in the north and northeast;

♦ Antigonish Basin, Antigonish High Massif, offshore and St. Georges Bay in

the west and southwest;

♦ Gulf of St. Lawrence Basins in the west.

Since the first petroleum hole was drilled in 1869 in the Lake Ainslie area (west-

central part of the Cape Breton Island), interest in finding oil and gas resources

within Cape Breton Island was variable, but quite high especially during the 1960s,


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1970s, and 1980s. A recent discovery of commercial accumulations of natural gas

(McCully Gas Field of Corridor Resources et al.) in southeastern New Brunswick,

which is located within a similar geological framework of the onshore portion of

the Maritimes Basin such as in Nova Scotia have generated unprecedented

interest in the “onshore” petroleum potential within Eastern Canada. About 165

wells (both petroleum and mineral) have been drilled throughout all of Cape Breton

Island to evaluate base metals, salt, potash, limestone, petroleum and coal

resources. In the 1970’s, three offshore wells (North Sydney F-24, North Sydney P-

05, and St. Paul P-91) and one onshore well (Birch Grove #1) was drilled in search

of petroleum in the Sydney basin (Tables 1a and 1b).

Currently, petroleum prospects in onshore Nova Scotia (especially within Cape

Breton Island) have generated more interest to petroleum exploration companies

due to available cheaper land positions, the major hydrocarbon discoveries in a

similar geological framework in New Brunswick, the relatively inexpensive

exploration costs, and numerous oil and gas seeps and shows. Currently, four

companies hold exploration licenses within both the offshore and onshore portions

of Cape Breton Island (Corridor Resources, Hunt Oil Canada, Contact Exploration

Inc and PetroWorth Resources Inc.).

1.3. OBJECTIVES AND ACHIEVEMENT Other than the vast geological data available, only a few earlier geochemical

studies have been useful for building a preliminary framework of the petroleum

systems within various subbasins of Cape Breton Island. The current research

contract was initiated as none of these studies have evaluated the preliminary

assessment of the petroleum potential of various sub-basins within Cape Breton

Island related to play types and their relation to petroleum system parameters.

In order to fulfil the commitment of the contract, the final report has systematically

established a comprehensive synthesis on the preliminary framework of the

petroleum system components within selected subbasins: Mabou-Ainslie


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subbasin in western Cape Breton; Bras d’Or subbasin and Loch Lomond

subbasin of the Central Cape Breton; and Sydney subbasin (from earlier data by

permission from Total Inc., Calgary, Alberta). The following components of the

petroleum systems have been evaluated:

1.3.1. Geological Components:

Illustrated the structural and stratigraphic configuration of

each subbasin from 2D seismic data and other geological

analysis

Generalized assessment of various play types in relation to

structure and salt tectonics

Analyzed the porosity, permeability, and grain density of

selected reservoir rocks from the Horton, Windsor, Mabou,

and Cumberland Groups of three major subbasins

1.3.2. Geochemical Components

Defined the organic richness and source rock potential of various

units at various stratigraphic intervals (example: Horton, Windsor,

etc.) from selected core and cuttings samples applying total organic

carbon determination and Rock-Eval pyrolysis;

Illustrated the maturity of sediments and maturation profile of

various wells from the Horton, Windsor, and Cumberland Groups of

selected subbasins by vitrinite reflectance measurement;

Characterized the possible nature of various seeps and stains

within the candidate source rocks and oil stained reservoir rocks of

selected play types. This has been performed using the

characterization of analyzed oil or oil stains and oil-source rock

correlation using bitumen extraction, liquid chromatography, gas

chromatography, and gas chromatography mass spectrometry.

1.3.3. Risk Assessment and Defining the Petroleum Potential:


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Evaluated the porosity and permeability of the hydrocarbon

reservoirs from various play types mainly within the Horton and

Windsor groups,

Preliminary assessment of the risk factors within potential play types

and petroleum system time events from limited seismic or other

geological data and the pattern of the hydrocarbon charge within

various reservoirs. However, this issue could not properly be defined

as the timing of hydrocarbon generation and expulsion by numerical

modelling has not been performed.

2. GEOLOGICAL OVERVIEW - THE MARITIMES BASINS The Maritimes Basin is located in the north-eastern part of the Appalachian

Orogen and is one of several Late Palaeozoic basins that occur along the

eastern margin of North America (Figures 1 and 2a). It underlies an area of

approximately 250,000 square kilometres which was initiated during a rifting

event in the Late Devonian and continued to form until the Early Permian.

(Figures 1 and 2a). This has formed a series of interconnected subbasins with

intervening platforms or horsts. The present day configuration of the Basin is a

preserved remnant of a larger centre of Permian-Carboniferous sedimentation

(Calder; 1994; Roliff, 1962; St. Peter, 1994). Based on the thermal evolution of

the Maritimes Basin, it is considered that this basin forms an erosional remnant

of a much larger system. The thermal maturity analysis has indicated that at least

two kilometres of sediments have been removed from the overall sedimentary

package (Hacquebard and Cameron, 1989; Mukhopadhyay, 1991; Ryan, 1993).

The Maritimes Basin contains a thick (up to 12,000 metres) accumulation of

stratigraphic sequences, which is dominated by terrestrial clastic rocks with

subordinate amounts of shallow marine clastic, carbonate, evaporite and volcanic

rocks of the Late Devonian to Early Permian age. During the Late Devonian to

Late Mississippian, tectonic subsidence was characterized by irregular

subsidence in half-graben style depocentres. This style of subsidence evolved


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into more uniform, regional subsidence during the Pennsylvanian and Early

Permian. A late Mississippian to Early Pennsylvanian period of uplift and erosion

resulted in the presence of a widespread angular unconformity. Maximum burial

was reached in the Middle Permian which was closely followed by regional

exhumation that took place from the Late Permian to the Late Triassic (Ryan and

Zentilli, 1993).

Carboniferous strata within the Maritimes Basin were affected by three periods of

deformation: 1) Middle Mississippian folding and faulting resulted in widespread

uplift and erosion prior to deposition of the Viséan Windsor Group; 2) Late

Mississippian to Early Pennsylvanian folding and faulting, which deformed all

Mississippian strata and was coincident with salt diapir formation; 3) Late

Carboniferous deformation (Allegheny Orogeny) resulted in strike-slip

displacements locally and by provided a distal source of clastic sediment from

the central Appalachian Orogen (Gibling, 1992).

3. GEOLOGICAL FRAMEWORK – CAPE BRETON ISLAND The Late Devonian to Permian sediments of Cape Breton Island is a part of the

post-Acadian orogenic succession and overall Maritimes Basin that covers the

area between Western Newfoundland and the Gaspe Peninsula in Quebec

(Figure 2). Cape Breton Island is approximately 200 kilometres long and from 50

to 150 kilometres wide with a total landmass area of about 14,000 square

kilometres. Within southwestern Cape Breton Island subbasins, the ground

surface rises from sea level, around the coastline, to a maximum elevation of 300

metres within the Mabou and Creignish Inliers (Figures 3b and 5).

Cape Breton Island is located in the southeastern part of the Magdalene

Subbasin which is a component of the regional Maritimes Basin (Figure 3a). It is

a large structural basin that occupies various subbasins (Boehner and Giles,

1993): Western Cape Breton Subbasins (mainly Mabou-Ainslie Subbasin); Central

Cape Breton (River Dany’s Depocentre, Bras d’Or Subbasin; Loch Lomond


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Subbasin [or St. Peter’s-Loch Lomond Depocentre]; Glengarry Half-Graben); and

Sydney Subbasin (Figure 3b; Fig. 5 [1:250,000 map in pocket]).

The central, south-western, and south-eastern Cape Breton Island is 10,000

square kilometres in size, approximately half of which is underlain by Late

Devonian to Pennsylvanian subbasins that are preserved remnants of the

regional Maritimes Basin. These subbasins contain up to 7,000 metres of strata

that ranges in age from Late Devonian to Pennsylvanian. The major sedimentary

units within various basin and subbasins of Cape Breton Island are lower to

Upper Carboniferous rocks. The Middle Devonian McAdams Lake Formation in

the Sydney Subbasin is the oldest sediments within Cape Breton Island.

Since the 1960’s (especially between 1980-2001), a vast amount of geological

work have been performed within these basins by geoscientists from the Nova

Scotia Department of Natural Resources (previous Nova Scotia Department of

Mines and Energy), Geological Survey of Canada (Atlantic), Dalhousie University,

and various other universities and research organizations (Barr et al., 1996;

Boehner, 1986; Boehner and Giles, 1986, 1993; Durling et al., 1995a, 1995b;

Gibling et al., 1987; Hamblin, 1989; Lynch and Brisson, 1993; Pascucci et al. 2000;

Giles and Boehner, 2001; for details see the Bioliography Section).

This current petroleum system study concentrated on three zones within Cape

Breton Island: Western Cape Breton Subbasins, Central Cape Breton Subbasins,

and the Sydney Subbasin. For the Sydney Basin, an earlier petroleum system study

by Mukhopadhyay (2000; permission from Total Inc., Calgary, Alberta) had been

taken as part of a comprehensive study. No new work on Sydney Basin has been

performed for the current contract.

Similar to other Palaeozoic basins in onshore Nova Scotia, the subbasins of

Cape Breton Island contain sediments from the Late Devonian (McAdams lake

Formation; Sydney Basin), Horton (Tournaisian), Windsor (Visean), Mabou


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(Numerian), Cumberland (Westphalian-Stephanian)), and Pictou (Permian)

Groups. A correlative stratigraphic nomenclature of the Western/Central

Subbasins and Sydney subbasin has been included in Figure 6a, which shows

differences in nomenclatures for the Windsor Group sediments within Cape

Breton Island.

3.1. GEOLOGY: HORTON GROUP (LATE DEVONIAN TO EARLY CARBONIFEROUS [TOURNAISIAN]) 3.1.1. Distribution and Thickness The Horton Group outcrops extensively within the Ainslie depocentre, the St.

Peters – Loch Lomond depocentre and the Sydney Basin. The Horton Group has

been penetrated by eight (8) petroleum exploration wells and numerous core

holes (see Table 1). Figures 3b and 4 (in pocket) illustrate the distribution of the

Horton Group rocks in various subbasins within Cape Breton Island. The Horton

Group rocks were collected from a few wells on Cape Breton Island: Chevron

Irving Mull River No.1, Imperial Mabou No.1, Lake Ainsle-88-1, and Saarberg

wells. Accordingly, outcrop samples collected for this contract and by Hamblin

(1989) have been used for this study (Appendix 3a and Table 2).

The thickness of the Horton Group is quite variable, but generally increases in

thickness with increasing distance from basement blocks. The Group consists of

a maximum of 4,000 metres of terrestrial clastics that include alluvial fan, braided

fluvial and lacustrine sedimentation (Hamblin, 1989; Humblin and Rust, 1989).

3.1.2. Lithology and Depositional Environment The Horton Group is from the Late Devonian to Mississippian (Tournasian) in

age and is comprised of the initial, post-orogenic (Acadian Orogeny), terrestrial

clastic deposition within the Maritimes Basin. Horton Group strata were deposited

in a series of half-grabens in a large intracontinental rift and/or pull-apart system.

The system was located at a palaeolatitude of 10o to 15o S in a warm semi-arid

climate (Hamblin and Rust, 1989; Martell and Gibling, 1996; Murphy and Rice,


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1998). Within Western and Central Cape Breton Island, the Horton Group is

subdivided into three (3) formations which include the following (from oldest to

youngest) (Hamblin and Rust, 1989; Lynch and Brisson, 1995):

3.1.2.1. Creignish Formation

The Creignish Formation occupies the lower-most strata of the Horton Group. It

is from 500 to 2,000 metres thick and covers most of western, central, and

southern Cape Breton Island. The Formation is dominated by reddish-brown and

grey conglomerate and pebbly sandstone with lesser amounts of reddish-brown,

find grained sandstone and minor siltstone (Hamblin and Rust, 1989). The top of

the Creignish Formation contains grey arkosic and quartzose sandstones (Giles,

1993).

Most of the strata included in the Creignish Formation were deposited in broad,

shallow braided fluvial systems in areas proximal to basin margins and in

mudflats in areas distal to basin margins. The sediments were deposited in a

warm, semi-arid climate (Hamblin and Rust, 1989). Alluvial fan facies are not

evident, perhaps due to erosion.

3.1.2.2. Strathlorne Formation

The Strathlorne Formation, comformably overlies the Creignish Formation,

occupies the middle of the Horton Group, and is from 100 to 600 metres thick

(Hamblin and Rust, 1989). The Strathlorne Formation is dominated by grey and

dark grey mudstones and siltstones with lesser amounts of interbedded, grey

sandstones and minor, thin carbonate beds (Hamblin and Rust, 1989).

Within the Strathlorne Formation, well sorted grey quartzose sandstones are

found to be 2 to 15 metres in thicknesses (Hamblin and Rust, 1989; Giles, 1993).

The strata of the Strathlorne Formation were deposited in fault-bounded,

lacustrine settings. The grey mudstones and siltstones were deposited in

moderate depth lakes; the sandstones were deposited in protruding lacustrine


19

deltas and beaches. The Strathlorne Formation is correlative to the gas- and oil-

productive Albert Formation in New Brunswick.

3.1.2.3. Ainslie Formation

The Ainslie Formation, comformably overlies the Strathlorne Formation,

occupies the top of the Horton Group, and is from 200 to 650 metres thick

(Hamblin and Rust, 1989). The Ainslie Formation consists of reddish-brown to

grey fine to coarse grained terrestrial clastics that are dominated by dark grey

shales (Hamblin and Rust, 1989).

Strata of the Ainslie Formation were deposited in a drainage system that has

been originated within the basin margin to basin central settings. Alluvial fan and

proximal braid plain deposition were dominant in areas proximal to the basin

margin. Medial zones were dominated by low to moderate fluvial channels that

extended to low relief, low sinuosity channels and extensive floodplains.

3.1.3. Age and Relations with other Units On the basis of miospores, megaflora and invertebrates, the age of the Horton

Group has been established as almost entirely Tournaisian, with the exception of

the lower-most strata that is Latest Devonian (Playford, 1963; Hacquebard, 1972;

Utting, 1987; Utting et al, 1989; Martel et al, 1993; Martel, 1996).

At numerous outcrop locations throughout the Maritimes Basin, the Horton Group

is observed to overlie basement rocks (Meguma Group, Ordovician) with

pronounced angular unconformity (Martel and Gibling, 1996). At outcrop

locations within the Windsor and Antigonish-Mabou Subbasins, the Horton Group

is observed to be concordantly overlain by the Windsor Group in a boundary that

is probably disconformable.


20

3.2. GEOLOGY: WINDSOR GROUP (VISÉAN) 3.2.1 Distribution and Thickness The Windsor Group crops-out extensively within southern Cape Breton Island

and has been penetrated by numerous petroleum exploration wells that have

core samples. On southern Cape Breton Island, the Windsor Group reaches a

maximum stratigraphic thickness of 1,200m. Thicker sections have been

measured where diapirism and structural repetition have occurred. A complete

lithostratigraphy of the Windsor Group from Central Cape Breton Subbasins is

illustrated in Figure 6b (after P. Giles, personal communication, 2000;

Mukhopadhyay, 2000: Permission from Total Inc., 2004).

3.2.2. Lithology and Depositional Environment Within southern Cape Breton Island, the Windsor Group has been subdivided

into four (4) units; from oldest to youngest, they are: the Lowermost Windsor

Group or Macumber Formation, the Lower Windsor Group, the Middle Windsor

Group and the Hood Island Formation (Giles, 1993).

3.2.2.1. Lowermost Windsor Sub-Group: Macumber Formation

The Macumber Formation is a regionally extensive and distinctive stratigraphic

unit that is found at the base of the Windsor Group throughout the Maritimes

Basin. The Macumber Formation conformably or disconformably overlies the

Horton Group and is from several metres to 20 metres thick (Giles, 1993). The

Formation consists entirely of limestone, including laminated lime mudstone and

peloidal lime mudstone. Many exposures of the Macumber Formation contain

bedding-parallel layers of limestone breccia and calc-mylonite which may be

indicative of a semi-regional, bedding-parallel fault that has been called the

“Ainslie Detachment” (Giles, 1993). A highly fossiliferous and porous facies

equivalent of the Macumber Formation occurs where the Macumber Formation

occurs as onlap directly over the basement rocks. Carbonate build-ups of this

type are found in the Ainslie Depocentre, St. Peters-Loch Lomond Depocentre


21

and the Sydney Subbasin. Such build-ups are similar to those found on the

mainland Nova Scotia and are termed as Gay’s River reefs.

The depositional environment of the Macumber Formation is the subject of

contradictory opinions; however, the preponderance of the evidence indicates

deposition in a subtidal setting following a major marine transgression and a

subsequent slow regression (Schenk, 1967; Schenk et al., 1990, 1994; Boehner

et al; 1989; Boehner and Giles, 1993).

3.2.2.2. Lower Windsor Sub-Group

The Lower Windsor Sub-Group conformably overlies the Macumber Formation

and is from 300 to 500 metres thick. The Lower Windsor Group is comprised of

almost entirely anhydrite, gypsum, salt with rare occurrences of limestone. The

Lower Windsor Sub-Group may possibly be deposited within a restricted, marine

basinal setting (Boehner and Giles, 1993).

3.2.2.3. Middle Windsor Sub-Group

The Middle Windsor Sub-Group conformably overlies strata of the Lower

Windsor Group and is of uncertain thickness due to deformation and diapirism.

Comparisons of the Middle Windsor to stratigraphic packages in other parts of

the Maritimes Basin would suggest this unit is several hundred metres thick.

Although direct evidence is lacking, the Middle Windsor Group appears to be

dominated by anhydrite and halite with interbedded carbonates and siltstones.

Earlier studies have suggested that these sediments have been deposited in a

restricted marine basinal setting (Boehner, 1986; Boehner and Giles, 1993).

3.2.2.4. Hood Island Formation

The Hood Island Formation conformably overlies strata of the Middle Windsor

Group and is from 100 to 700 metres thick. The Hood Island Formation is

dominated by reddish-brown siltstones and very fine grained sandstones with


22

minor, interbedded carbonates and anhydrite (Giles, 1993). The Hood Island

Formation was deposited in a alternating intertidal and supratidal marine setting.

3.2.3 Age and Relations with other Units On the basis of miospores, megaflora and invertebrates, the age of the Windsor

Group has been established as Viséan (Utting, 1988). In many locations within

the Maritimes Basin, outcrops of Windsor Group strata are observed to overlie

basement rocks with pronounced angular unconformity (Bell, 1929; McCutcheon,

1981; Boehner, 1986 & 1993). Also, at many locations within the Maritimes

Basin, the Windsor Group is observed to overlie the Horton Group concordantly

(example in Cape Breton Island: Port Dauphin Section, Lake Ainslie area).

However, within New Brunswick, the Windsor Group is observed to overlie the

Horton Group Albert Formation with angular unconformity (Clint St. Peter,

personal communication). Also, within the Moncton Subbasin, the Horton Group

is more tightly folded, more extensively faulted than the Windsor Group and is

seen to unconformably underlie the Windsor strata in several seismic sections

(Clint St. Peter, personal communication). The preponderance of erosional

surfaces indicates there is a widespread unconformity between the Horton and

Windsor Group strata within the onshore portion of the Maritimes Basin. The

Windsor Group is conformably overlain by the Mabou Group (Bell, 1929; Ryan

and Boehner, 1994; Boehner, pers. comm.).

3.3. GEOLOGY: MABOU GROUP (VISÉAN - NAMURIAN) 3.3.1 Distribution and Thickness The Mabou Group crops-out broadly within the Ainslie Depocentre, the St. Peters

– Loch Lomond Depocentre and locally with the Sydney Subbasin. The Mabou

Group has been penetrated by four (4) petroleum exploration wells and

numerous core holes. Chip and core samples of the Mabou Group are available

from the Port Hood No.1, Mabou No.1, Mary No.1 and Mac No.1 Wells.


23

The Mabou Group is from 200 to 800 metres thick and has been subdivided into

two (2) formations: the Hastings Formation and the Pomquet Formation. In the

Sydney Basin, the Mabou Group has been subdivided into Cape Dauphin

Formation and Point Edward Formation,

3.3.2 Lithology and Depositional Environment The Mabou Group strata reflects the resumption of predominantly terrestrial

sedimentation. The Group is comprised of grey and reddish-brown mudstones

and siltstones with minor sandstone intervals that are generally less than 3

metres thick (Bell, 1964)

3.3.3. Age and Relations to Other Units

The Mabou Group is Late Viséan to Early Namurian in age (Ryan and Boehner,

1994). The group conformably overlies the Windsor Group and is conformably

overlain by the Cumberland Group (Morien Group in Sydney Subbasin).

3.4. GEOLOGY: CUMBERLAND GROUP (PENNSYLVANIAN) 3.4.1. Distribution and Thickness The Cumberland Group (Morien Group in Sydney Basin) is exposed extensively

with the Sydney Subbasin and the St. Peters – Loch Lomond depocentre and is

locally exposed within the Ainslie Depocentre. Within Southwestern and Central

Cape Breton Island, the Cumberland Group is up to 4,000 metres thick and is

subdivided into three (3) formations: the Port Hood, the Henry Island and the

Inverness Formations.

3.4.2. Lithology and Depositional Environment The lower 2,000 metres of the Cumberland Group (Margaree Member of the Port

Hood Formation) is dominated by reddish-brown siltstones and mudstones with

abundant grey multistoried channel sandstones. Overlying the Margaree Member

a 700 metres thick section of the Colindale Member of the Port Hood Formation

is characterized by an abundance of grey to black mudstones with channel


24

sandstones similar to the Margaree Member. The section also includes organic-

rich mudstones and several coal seams. Overlying the Colindale Member is a

650 m thick section that is similar to the Margaree Member of the Port Hood

Formation. The upper 600 metres of the Cumberland Group (Inverness

Formation) is dominated by grey coarse grained sandstones with subordinate

grey mudstones and coal seams.

3.5. GEOLOGY: SYDNEY BASIN AND SURROUNDING AREAS

(contribution of Dr. P. K. Mukhopadhayay from Mukhopadhyay, 2000:

Permission from Total Inc., 2004)

The Sydney Subbasin has both a northeast-southwest structural trend in the

Namurian or older strata and an east-west trend in the Late Westphalian strata

(Boehner and Giles, 1993). The eastern boundary within the offshore extension

of the Sydney Basin has not yet been properly defined. The basement unit as

observed in the Boisdale and Coxheath Hills consist of Precambrian and lower

Paleozoic rocks. Similar rocks have also been noticed in other parts of Cape

Breton Island (Boehner and Giles, 1993; Pascucci et al., 2000). The major

sedimentary units in the Sydney Subbasin are Lower to Upper Carboniferous

rocks although sediments from the Middle Devonian McAdams Lake Formation

also occur near the Boisdale and Coxheath Hills.

Similar to other Paleozoic basins in onshore Nova Scotia, Sydney Basin contains

sediments from the Horton, Windsor, Mabou, Cumberland (Morien Group for this

basin), and Pictou Groups. The Middle Devonian McAdams Lake Formation

organic rich coaly shale and coarse siliciclastic rocks are the oldest sediments in

the Sydney Basin. However, coarser conglomeratic alluvial fan deposits of the

Lower Carboniferous Grantmire Formation (Horton Group; Tournaisian age) are

the lowermost strata in the onshore Sydney Basin and surrounding areas. This

formation unconformably overlies the Hadrynian-Devonian basement mostly of

lower Paleozoic rocks (Boehner and Giles, 1993). The lower part of the two

offshore wells (North Sydney F-24 and P-05) has also encountered the coarse


25

clastic rocks of the Grantmire Formation. Some doubtful thin fine to medium-

grained sandstone from the Horton Group has also been encountered in some

areas of onshore Sydney Basin and in areas that are in close proximity to the

Sydney Basin (example: Ingonish Beach). The sandstone from Ingonish Beach

has been identified as Windsor sediment by Pascucci et al., (2000) although the

earlier map of Cape Breton Island from the Nova Scotia Department of Mines

and Energy (1979) designates this rock as Horton Group. The organic-rich

lacustrine shales (kerogen Type I and II) from the Middle Horton Group that have

generated crude oil in the Stony Creek Field of New Brunswick have not been

encountered in the onshore Sydney Basin.

The marine Windsor Group sediments (Visean age) lie both conformably and

disconformably over the nonmarine Horton Group coarser clastics. The Windsor

Group within the Sydney Basin contains highly variable thickness (few meters to

more than 1500m; an average is between 700 -1000m). The Windsor Group has

five subdivisions in the Sydney Basin (Boehner and Giles, 1993):

The basal Gays River Formation marine carbonate build-ups (highly

fossiliferous limestone) and equivalent deep water, marine, anoxic Macumber

Formation (alternately Macbeth Brooks Formation) contain laminated

limestone and calcareous shales.

The Sydney River Formation comprises interbedded red and grey siliciclastics

(siltstone to conglomerate), evaporites (anhydrite, gypsum and rare salt) and

thin fossiliferous carbonates. This group has various salinity gradients.

The Kempt Road Formation comprises the major salt units. It contains salt,

potash, and grey to green claystone, anhydrite, and siltstone. This formation

was deposited under increasing marine saline condition although it has some

lateral basinal facies (Bridgeville Formation).

The Meadows Road Formation is an interstratified sequence of gypsum, red

and green claystone, siltstone, sandstone, and conglomerate with several

dark algal-rich and fossiliferous marine carbonate units.


26

The topmost Windsor Group sediments are the Woodbine Road Formation. It

contains two facies variations: one marginal conglomeratic facies and the

other basinal facies comprising of fine-grained redbeds, continental clastics

such as shale, siltstone, and sandstone. It also contains marine oolitic algal

and micritic argillaceous limestone and dolstone and some gypsum and

anhydrite.

The overlying lacustrine to alluvial Mabou Group (Namurian age) consists of

sandstone, siltstone, limestone, and black shale of the Point Edward and Cape

Dauphin formation. The Upper Carboniferous strata in this basin unconformably

overlie the Mabou Group. The Morien Group (equivalent of Cumberland Group of

other onshore basins from Nova Scotia) has the following lithostratigraphic

subdivisions:

It includes thick sandstone and siltstone of the South Bar Formation

Some 600 m thick sediments of the Sydney Mines Formation (productive coal

measures associated with the sandstone, siltstones, and organic-rich shales)

ranges in age from Westphalian C to Stephanian. The sediments were

deposited in an alluvial and coastal plain paralic environment (Hacquebard

and Donaldson, 1969). The basin is the largest coal basin in eastern Canada

that covers the area below the Atlantic Ocean with an unknown aerial extent

but thought to extend seaward to Newfoundland.

Most of the major coal seams occur within the Sydney Mines Formation

(Westphalian D to Stephanian in age) while the South Bar Formation

(Westphalian B-C) contains only one coal seam (Tracy). The three major seams

(Hub, Harbour, and Phalen) and the other seams such as Gardiner, Emery,

Bouthillier, Backpit, Spencer, and Tracy represent the major coal resources in

eastern Canada.

3.6. SEISMIC DATA, MAJOR STRUCTURES, AND PLAY TYPES 3.6.1. Seismic Data Available for This Study


27

In 1981, Chevron Standard Ltd. shot 159 kilometres of 1200%, onshore seismic

data in the Ainslie depocentre using vibroseis techniques (Figure 4). The

following seismic profiles were available for our examination:

Company Seismic Line Distance Shot Chevron Standard Inc. 11-F-NW 37 06 kilometres 11-F-NW 47X 07 kilometres 11-F-NW 52Y 31 kilometres 11-F-NW 60 05 kilometres 11-F-NW 62 29 kilometres 11-K-SW 08 40 kilometres 11-K-SW 14 30 kilometres 11-K-SW 40 11 kilometres Total of All Lines 159 kilometres The quality of the Chevron data varies from poor to fair.

In 1980, Chevron Standard Ltd. shot 490 kilometres of 1200%, marine seismic

data in the Bras d’Or Lakes of central Cape Breton Island. All of these data is

poor and none of these profiles provide useful images for subsurface mapping

(Figure 4).

Chevron Standard Ltd. shot four (4) short lines of reflection seismic in the

Malagawatch area in 1981; however, these profiles were not availale for our

examination.

In 1972, Murphy Oil Limited shot 53 kilometres of reflection seismic in Sydney

Subbasin. These lines were not available during the contract period. Newer

seismic acquired by Vintage Petroleum in 2003 was not available for our

examination.


28

3.6.2. Major Structures

3.6.2.1 Introduction

The general structural configuration of the Western and Central Cape Breton

Island area is dominated by subbasin-bounding, northeast-trending, strike-slip

and oblique fault systems. The subbasins and depocentres that form the subject

of this report, are down-faulted, preserved remnants of the regional Maritimes

Basin.

Extensional and transgressional stresses have resulted in a somewhat complex

structural configuration within most subbasins, which result in the presence of

steep normal faults, moderate- to low- angle reverse faults, faulted anticlines and

deformed diapirs.

Due to the paucity of deep well information and rather poor seismic data, the

internal structure of most of the depocentres has not been well defined.

3.6.2.2. Ainslie Depocentre

The Mississippian strata of the Ainslie depocentre is configured into several,

northeast-trending, domal anticlinal structures defined by Horton Group strata

with intervening, tight synclinal structures that preserve Windsor and Mabou

Group sediments. The outer limbs of the anticlinal structures are generally

steeply dipping and defined by faults suggesting the anticlinal structure may be

the result of differential compaction over pre-Carboniferous basement highs

(Giles et al, 1997).

The presence of large stratigraphic gaps within the Windsor Group may be

explained by the effect of a major, extensional, bedding-parallel, detachment fault

(Ainslie Detachment) that is located at the top of the Macumber Formation

(Lynch and Giles, 1995; Lynch and Brisson, 1996; Giles et al, 1997).


29

Figure 7a is the uninterpreted seismic profile Chevron 62Y which is reasonably

close to two (2) exploration wells – Mac No.1 and Mabou No.1. Figure 7b is our

interpretation based on the profile-based outcrop mapping, deep well information,

and previous published reports (Durling et al., 1995). Our interpretation presents

a structural style that is dominated by northwest directed moderate to low angle

thrust faults. Between short points 1900 and 2350, the Creignish Formation is

interpreted to be thrusted over a stacked, moderately continuous, reflections that

may be Late Devonian volcanics and siliciclastics an/or Horton Group strata.

Between short points 2400 and 2550, the Horton and Windsor Group is

interpreted to be thrusted over the Ainslie Formation along a detachment zone at

the base of the Windsor Group.

Figure 8 is a structural cross section through Port Hood No.1, Mac No.1, Mabou

No.1, Mull River No.1 and MacIsaac No.1. This cross section attempts to resolve

the complex structural style of the Ainslie depocentre by retaining the proposed

thrust fault structural style. The structural interpretations presented in Figure 7B

and 8 differ from some previous interpretations, which include northwest dipping

thrust faults in addition to southeast dipping thrust faults (Durling et al., 1995;

Giles et al, 1997).

3.6.2.3. Bras d’Or Subbasin

The Bras d‘Or Subbasin is an oval-shaped, northeast-trending synclinorium that

has been affected by syn- and post-Carboniferous folding and faulting. The

Subbasin has prominent northeast structural trend that is typified by broad, open

folds and faults (Lynch and Brisson, 1996).

Most of our understanding of the deep subsurface structural style of the Bras

d’Or Subbasin comes from the core holes and petroleum wells drilled in the

Orangedale – Malagawatch area (Figure 4) in the southwest part of the

Subbasin. In this area, Windsor Group strata are in direct contact with overlying


30

basement rocks with angular unconformity. Horton Group strata are postulated to

be present in basin-centre locations.

Figure 9 is structural cross-section through the Orangedale-Malagawatch area,

which demonstrates the general stratigraphy and structure. Strata of the Windsor

Group appear to be configured in broad open fold structures; however on a scale

of hundreds of metres the structural configuration is characterized by tight,

recumbent folds (Giles and Boehner - Field Trip Guide, 2001).

3.6.2.4 Sydney Basin

The Sydney Basin is a northeast-dipping, northeast-elongated and fault-

truncated synclinorium that has been affected by syn- and post-Carboniferous

folding and faulting. The Subbasin has prominent northeast structural trend that

has been modified by the superposition of an east-trending element in the

Pennsylvanian strata of the Morien Group (Boehner and Giles, 1986; Boehner

and Giles, in press).

The southwestern part of the Sydney Basin boundary is a profound angular

unconformity with the East Bay Block Neoproterozoic (Hadrynian)-Devonian

basement. The Pennsylvanian (Upper Carboniferous) strata within the basin area

are folded into broad, open asymmetric synclines and anticlines with arcuate fold

axis (Boehner and Giles, 1986; Boehner and Giles, in press). Bedding dips are

typically from 5 to 12 with steep dips in the flexures proximal to the underlying

basement blocks (Boehner and Giles, 1986; Boehner and Giles, in press).These

folds appear to be related to the faulted and folded Mississippian rocks situated

on the basement fault blocks (Boehner and Giles, 1986; Boehner and Giles, in

press).

3.6.3. Play Types A conceptual model has been evolved, which includes various possible play

types within the Horton, Windsor, Mabou, and Cumberland Group of sediments


31

(Figure 10). The following is a list of some of the more specific play types within

the Horton and Windsor groups that could be documented.

3.6.3.1. Horton Group

Play Type #1 Sandstone reservoirs within the Strathlorne and Ainslie

Formation that occur within anticlinal structures forming

combination, stratigraphic-structural traps (such as the Stoney

Creek Gas and Oil Field);


Formations that occur beneath gently-dipping reverse faults;


Formations that exhibit stratigraphic pinch-out characteristics;

Play Type #4 Sub-salt sandstone reservoirs within the Strathlorne and Ainslie

Formations;

3.6.3.2. Windsor Group

Within the Macumber Formation of the Windsor Group and the Lower and Middle

Windsor Group, there is a possibility of the presence of previously unidentified

biohermal lithofacies that may have developed along basin margins and on

subtidal paleo-topographic highs within the basin. Fractured carbonate reservoirs

are another possible reservoir type particularly within the Macumber Formation

where the presence of chert may enhance fracture density. This is evident in

outcrop where fractures are generally spaced from 10 to 20 cm apart (field and

core observations, this contract).

Within the Windsor Group, limestone and sandstone reservoir rocks may be in a

trap position as (Figure 10):


32

Play Type #5 Carbonate bioherm reservoirs either fringing the basin margin or

in the vicinity of paleo-topographic highs within the basin;

Play Type #6 Up-dip truncation of carbonate reservoirs against evaporite

overhangs either generated by faulting or diapirism;

Play Type #7 Carbonate reservoirs that occur beneath gently-dipping reverse

faults up and down-thrown 3-and 4-way closures;

Play Type #8 Fractured Carbonate reservoirs in trap positions

3.6.3.3. Mabou Group

Previous research on the Mabou Group augmented by our field work indicated

that most Mabou sandstones are very fine grained to fine grained with typically

low estimated porosity and permeability (visual observations and few reservoir

data). The sandstones do not appear to offer much potential as reservoir rocks.

However, the Mabou Group offers a widespread seal to underlying and adjacent

petroleum accumulations

3.6.3.4. Cumberland Group

Cumberland Group contains broad thick sections of Pennsylvanian strata. Thick

sections of porous and permeable sandstone units are abundant throughout the

Cumberland Group, especially with the Port Hood Formation. Generally, the lack

of top seals in the vicinity of large structures limits the resource potential of these

units. However, alluvial channel sandstone reservoirs are possible exploration

target (Play Type #10).


33

3.7. HISTORY OF PETROLEUM EXPLORATION – CAPE BRETON ISLAND 3.7.1. 1850s to 1897 Between 1864 and 1880, several companies drilled at least ten (10) wells on the

west shore and three (3) wells were drilled on the east shore of Lake Ainsle (Bell,

1958; Norman, 1932A). Most of these wells were drilled to very shallow depths

of less than 200 metres; however, seven (7) were drilled to depths of greater

than 300 metres and are included in Table 1a and Figure 3 of this report.

Although the written record is vague and anecdotal on the subject of drilling

results, the presence of oil shows in many of these wells (example: sample no.

53b, Table 2) is fairly certain.

3.7.2. 1940 to 1944

Between 1941 and 1943, W. L. Whitehead supervised a comprehensive

geological research and mapping program of southwestern Cape Breton Island

(Ainslie depocentre) for the Cape Breton Petroleum Company. The work included

compilation of previous petroleum exploration, geological mapping and

presentation of play types and specific prospects. From 1942 to 1944, Lion Oil

Co. conducted a small seismic program which was followed by the drilling of two

(2) exploration wells in the vicinity of the Village of Mabou (Mac No.1 and Mary

No.1; Figures 3a and 3b). These wells were drilled to total depths of 1,701m and

2,094m. Both of these wells penetrated the Mabou and Windsor Groups.

3.7.3. 1958 to 1960

In the late 1950’s Imperial Oil Ltd. drilled two (2) exploration wells in southwest

Cape Breton Island (Ainslie depocentre) – Imperial Mabou No.1 and Imperial

Port Hood No.1 (Figure #3a, Table #1a). Imperial Mabou No.1 was completed in

1959 and was drilled to a total depth of 1,568 metres and penetrated the Mabou,

Windsor and Horton Groups. Imperial Port Hood was completed in 1960 and

drilled to a total depth of 3,000 metres and penetrated the Cumberland, Mabou

and Windsor Groups.


34

3.7.4. 1963 to 1968

Between 1963 and 1965 Pacific Petroleum Limited shot 53 kilometres of 100%,

onshore seismic data in southeast Cape Breton Island using the dynamite

vibroseis technique. In 1968 Murphy Birch Grove No.1 was drilled in southeast

Cape Breton Island (Sydney Basin) to a total depth of 1,344 metres. The well

penetrated the Morien Group (equivalent to Cumberland Group) and the Horton

Group with no significant petroleum shows. A subsequent 10 line seismic

program using a dynamite source was acquired by Murphy Oil to further evaluate

the area in November 1972.

3.7.5. 1980 to 2003

3.7.5.1. Chevron Standard Ltd.

In 1980, Chevron Standard Ltd. shot 490 kilometres of 1200%, marine seismic

data in the Bras d’Or Lakes of central Cape Breton Island. In 1981 the same

company shot 71 kilometres of 1200%, onshore seismic data in southwest Cape

Breton Island using vibroseis techniques.

In 1978, the Minerals Division of Chevron Standard Ltd. encountered a significant

oil show in one of its core holes located on the west side of the Bras D’Or Lakes

in central Cape Breton Island. Chevron re-drilled the original discovery hole

using rotary drilling techniques (Chevron Irving Bras D’Or No.1) to a total depth

of 216 metres. The well intersected the Windsor Group and entered basement at

210 metres. A drill stem test over the interval 193 to 216 m produced oil-cut mud.

Chevron Irving Bras d’Or No.2 was drilled at a location of 350 metres north, and

down-dip of Bras d’Or No.1 to a total depth of 375 metres. Both wells had

numerous oil shows throughout the Windsor Group section. In 1986, Chevron

drilled Mull River No.1 to a total depth of 1,502 metres near the crest of the Mull

River Anticline (Figs. 3a and 4). From spud to TD, the well penetrated 1,502

metres of Mississippian Horton Group strata with no oil shows.


35

3.7.5.2. Corkan Engineering

In 1983, Corkan Engineering drilled four (4) wells in the St. Peters – Loch

Lomond depocentre (Figure 4). The wells were drilled to total depths between

246 and 1,255 metres. The operations ceased due to frictional difficulties. Only

basic information on these wells was submitted to the regulator including total

depths, rig release dates and lithologic log summaries.

3.7.5.3. Vintage Petroleum Ltd.

Two modern seismic programs (Figure 4) were acquired in the summer of 2003

in the Bras d’Or Lake and Sydney areas (Figure 4). These programs were 23.2

km and 25.8 km, respectively. These seismic data will be kept confidential until

2008.

4. PREVIOUS STUDIES 4.1. PETROLEUM SEEPS AND SHOWS Numerous oil and gas shows have been encountered in various onshore wells

within Cape Breton Island (McMahon et al., 1986). Many of the wells from Jubilee,

Loch Lomond, Malagawatch and Glen Morrison areas of the Central Cape Breton

and Sydney subbasins have shown oil-stains or dead oil. Moreover, numerous oil

and natural gas surface seeps have also been recorded within these areas (Short,

1986). Reports of oil seeps emanating from outcrops of sandstone located near

MacIsaac Point on the west shore of Lake Ainslie, have been traced as far back

as the mid-1850s (Fowler et al., 1993; Norman, 1932A; Whitehead, 1941). Both

offshore wells (N. Sydney F-24 and P-05) in the Sydney Basin have various gas

shows. Figure 11a includes a summary of the petroleum shows that have been

observed within the Cape Breton Island.

4.1.1. Oil Seeps and Stains The following interpretation outlines various wells where oil shows or stains have

been encountered (Tables 1a and 1b and 2):


36

Lake Ainslie drillholes within the Western Cape Breton subbasins; various

wells (drilled both for water and petroleum) surrounding Lake Ainslie.

Malagawatch, Little Narrows, and Jubilee areas of the Central Cape Breton

subbasins (Figure 11b).

The Chevron-Irving Bras d’Or #1, Bras d’Or #3 or 3A-78, Malagawatch # M-1

and Malagawatch # M-2, and M-9 wells contain flow of live crude oil of 30-

40o API gravity (geochemistry included later). The flow of oil in Bras d’Or

#3A-78 is approximately 48 gallons/day although it has not been accurately

measured according to petroleum industry standards.

McIvor Point, Leitches Creek, Glen Morrison wells from the Sydney Basin.

In 1998, liquid hydrocarbons (condensate) were detected flowing from the

sandstone reservoir above the Hub seam inside the Prince Mine of the Point

Aconi area, Sydney Basin (Steve Forgeron, personal communications,

1998).

4.1.2. Gas Seeps and Shows The following are the list of wells or areas where gas seeps and shows were

reported:

The Cumberland-Morien Group sediments from Mabou and Port Hood wells

have numerous gas shows

Both offshore wells (N. Sydney F-24 and P-05) have numerous gas shows in

the deeper part of the Phalen coal mine in the Sydney Basin

The drilling data from DEVCO during the evaluation of the coal resources

within offshore mining areas, has encountered gas shows in at least five

wells

During the seafloor mapping of offshore areas close to the existing coal

mining zones of the Sydney Basin in the late 1990’s, significant gas seeps

have been observed along the fault planes offshore Sydney Basin (Courtney,

1996).


37

4.2. PETROLEUM GEOCHEMISTRY 4.2.1. Evaluation of Source Rock Potential and Maturation: Onshore Hamblin (1989) has studied the source rock potential of selected Horton Group

sediments from Western Cape Breton Island. Appendix C-1a and C-1b illustrate

the Rock-Eval pyrolysis data and Source Rock Potential Diagram (Tmax vs.

hydrogen index). Appendix C-1c illustrates the maturity data from Utting and

Hamblin, 1991 for the same set of samples. Most of the studied samples are

taken from the outcrop sections and are possibly oxidized. Accordingly, with the

exception of a few samples, all sediments have a low TOC content and

Hydrogen Index values (mostly less than 100 mg/g TOC). Comparing the

hydrogen index values in relation to maturity based on Tmax (oC) data, suggest

that only one sample is considered as kerogen Type II-III source rock. Otherwise,

all samples are considered as Type III gas-prone source rock to Type IV

nonsource rock (Appendix C-1b). Based on Tmax (oC) values, these sediments lie

within the immature to the principle phase of hydrocarbon maturity zone.

However, from a study of thermal alteration indices (TAI), Utting and Hamblin

(1991) have defined the maturity of these sediments in three broader zones that

includes “oil window, intermediate, and gas window” (Appendix C-1c).

Mukhopadhyay (1991) has studied the source rock potential and maturation of

the selected sediments from the Horton and Windsor Group of sediments of

western, northern, and central Cape Breton subbasins This data shows that the

Horton Group source rocks in western and northern Cape Breton are mainly gas-

prone Type III or nonsource rocks, whereas subbasins from the Central Cape

Breton Island have mainly kerogen Type II (oil-prone) and III (gas prone) source

rocks. On the other hand, selected samples from the Windsor Group sediments

from the western and Central subbasins, and from the Sydney subbasin from

Cape Breton Island have mainly kerogen Type II and III (oil- and gas-prone)

(Appendices C-2a, C-2b, C-2c, and C-2d). Appendix C-2e illustrates the maturity

of the analyzed sediments from the Cape Breton Island. The surface maturity

data from western and central subbasins of the Cape Breton Island (Lake Ainslie


38

and Malagawatch-Bras D’Or areas) lie within the “oil window (0.7 to 1.35% Ro)”

whereas sediments in the southern subbasin of the Cape Breton Island (Port

Hawkesbury area) lie beyond the principle phase of dry gas zone (>2.2% Ro)

(Appendix C-2e). The maturity of Horton Group sediments from all other areas is

highly variable and higher maturity is often related to a closeness of major thrust

or other fault zones. Mukhopadhyay (1991) has also suggested that the Windsor

and Cumberland Group of sediments at the outcrop within most subbasins of

Cape Breton Island lie within the “Oil Window”, whereas the Horton Group, with

the exception of shallow sediment within the Mabou and Lake Ainslie area are

overmature for oil generation and lie within the “Gas Window”.

Allen (1998) has analyzed the organic-rich shales from the Colindale Member of

Port Hood Formation (Cumberland Group) in Western Cape Breton subbasins

using Rock-Eval pyrolysis and visual kerogen analysis. Appendices C-3a and C-

3b show the list of analyzed samples and Rock-Eval pyrolysis data. Appendix C-

3b illustrates the Kerogen Type diagram indicating hydrocarbon potential of the

samples. According to this study, the following conclusions were made (Appendix

C-3a; Appendix C-3b):

The grey to black shales and limestones are mostly all organic-rich

(TOC>0.5%). About 50% of the samples have a TOC level higher than

1.5%

These organic-rich shales of the Colindale member are mostly gas- and

condensate-prone kerogen Type II-III and III source rocks. Visual kerogen

analysis revealed that these sediments contain a mixture of woody,

amorphous, and herbaceous plant materials with little or no algal remains.

The thermal maturity from Tmax (oC) data suggests that these shales lie

either in the immature zone or within the early stage of maturation

Most of the earlier works by Avery (Geological Survey of Canada unpublished

reports, 1977-1985) and Mukhopadhyay (1992) on various Cumberland Group

coal seams from the Sydney Basin suggest that the surface and near-surface


39

maturity of most coals vary from 0.6 to 1.0% Ro. However, the surface maturity

of the Mabou and Port Hood (Western Cape Breton subbasins) coal seams are

lower (0.4 to 0.6% Ro) compared to the Sydney Basin coal seams. Mossman

(1992) has reviewed some earlier works by Hacquebard (1986) on vitrinite

reflectance. Accordingly, he used selected samples (coal and coaly particles)

from the Horton Group, Macumber Formation, and Cumberland Group of the

Sydney Basin. He has suggested that the range of vitrinite reflectance for those

samples vary from 0.73 to 1.16% Ro.

4.2.2. Oil-Source Rock Correlation: Onshore Only one published document with geochemical characterization of three oil-stained

sandstones from the Horton Group and two oil-stained sandstone/limestone

reservoirs of the Windsor Group and one unpublished report on geochemical

characterization of one oil sample from the Lake Ainslie area of the Western Cape

Breton subbasin are available within the public domain (Fowler et al., 1993).

Fowler et al. (1993) has investigated the biomarker geochemistry and the

significance of some oil seeps near the Lake Ainslie area on western Cape

Breton Island that has been recorded since 1869 (Appendices C-4a and C-4b).

These five bitumen (oil stains) samples are either associated with upper Horton

Group (Ainslie Formation) or basal Windsor Group (Macumber Formation)

sediments. The nature of the biomarker distribution has indicated that these oil

seeps within the Lower Windsor and Horton Group reservoir rocks have

undergone varying degrees of biodegradation. They have concluded that these

bitumens have been derived from the same source rock unit and possibly from

the thinly bedded lacustrine dark grey mudstone or carbonates from the

Strathlorne Formation of the middle Horton Group (Tournaisian age). The high

abundance of carotenoids, regular sterane distributions, and very low abundance

of diasteranes imply that these source rocks are similar to the Frederick Brook

Member of the Albert Formation oil shale of New Brunswick or Strathlorne

Formation (Horton Group) of Cape Breton Island (Appendix C-4b). One oil


40

sample from a freshly drilled shallow well (Lake Ainsle-88-1) from the eastern

side of Lake Ainslie area has been geochemically fingerprinted by McMahon et al

(1989). They have indicated that the oil was sourced from organic material

deposited in a hypersaline, shale poor, carbonate-rich environment either derived

from the Horton or Windsor Group of sediments.

4.2.4. Source Rock Potential, Maturation, and Gas Analysis: Offshore Cooper et al (Robertson Research Report –1974 and 1976) have evaluated the

maturity and source rock potential with limited geochemical data for two offshore

wells that were drilled by Murphy Oil and Shell Oil (North Sydney P-05 and North

Sydney F-24/G-24). The vitrinite reflectance data of North Sydney P-05 well

suggests 0.75% Ro at 1780 ft or 542.5 m, 0.85% at 2500 ft or 762 m, and just

over 1.0% at the bottom of the well (5500 ft or 1676 m). Based on total organic

carbon, bitumen extract and hydrocarbons (in ppm) in the North Sydney F-24

well, they have concluded that a majority of the source rocks are gas- and

condensate-prone. However, some oil-prone source rocks are present in various

intervals. Based on the maturity of sediments and gas chromatograms of two

source rocks, they have suggested that these source rocks will generate mainly

light oil and condensate. They have indicated a significant gas potential between

zones at 847.3 m (2780 ft) to 1036.3 m (3400 ft) and 1237.5 m (4060 ft) to

1548.4 m (5080 ft). In the North Sydney P-05, Cooper et al (1974) has concluded

that the overall source potential for oil is fair to poor. However, they have

predicted significant gas potential within the zone 762 m (2500 ft) to 1189 m

(3900 ft).

Kendall and Altebaumer (1984) have performed a detailed maturity (vitrinite

reflectance) and geochemical evaluation (TOC, Rock-Eval, elemental analysis

[H/C vs. O/C diagram], bitumen extraction, gas chromatography of light

hydrocarbons and C15+ saturates) of the Petro-Canada St. Paul P-91 well. The

maturity data shows a vitrinite reflectance of 0.97% at 690 m to 3.19% at 2833 m


41

depth suggesting overmaturity of most of the drilled sections. As such, TOC and

Rock-Eval parameters (S1 and S2) are quite low suggesting a low hydrocarbon

potential for the well. However, the geochemical data of gas analysis from

various drill cuttings shows a high methane content (>1000 ppm) in the zone

between 1125 m to 1300 m and 2250 m to 2750 m although the authors have

suggested a possible contamination. Kendall and Altebaumer (1984) have

defined three good gas and condensate-prone source rock zones (800-820m,

1200m, and 1440m). For details of the stratigraphy of these zones, please see

the report of Kendall and Altebaumer (1984).

4.3. RESERVOIR ANALYSIS Only a few investigations have been conducted on the porosity and permeability of

clastic (Horton, Mabou, and Cumberland groups) and carbonate reservoirs

(Windsor Group) from Cape Breton Island (Shawnee Petroleum Limited, 1973;

Felderhof, 1975; Bibby and Shimeld, 2000). Possible siliciclastic reservoir rocks are

poorly defined but there are indications that porosity and permeability can be high

especially in the Horton and Mabou (Point Edward Formation) Group reservoirs

(Bibby and Shimeld, 2000). On the other hand, the reservoir quality (porosity-

permeability relationship) within the Windsor Group may be related to paleo-karsts,

large scale breccia, locally developed bioherms, unconformities, and dolomitization

(McMahon et al., 1989). The review by Bibby and Shimeld (2000) contains very few

analytical data on porosity and permeability of sediments from onshore Cape Breton

Island and offshore Gulf of St. Lawrence wells (Appendices C-5a and C-5b).

According to Bibby and Shimeld (2000), the Horton and Pictou group of sediments

have the highest porosity and permeability distribution (Appendix C-5b). Shawnee

Petroleum Limited (1973) has shown some porosity data of the sediments from the

Inverness area (Western Cape Breton subbasin) while evaluating the resource

potential of selected onshore Nova Scotian basins. Accordingly, Shawnee

Petroleum has estimated 15% porosity for the reservoir sandstones in the Inverness

area that has 100 ft (30.5 m) pay zone.


42

4.4. FISSION TRACK ANALYSIS AND PETROLEUM SYSTEM MODELLING: OFFSHORE Ryan et al (1990) have investigated the thermal evolution of the Maritimes Basin

(including the offshore Sydney basin) using the Apatite Fission Track analysis.

Accordingly, they have postulated the following events for the thermal evolution of

the Maritimes Basin:

The basin underwent rapid sedimentation and burial from about 320 to 290

Ma

There was basin-wide erosion that lasted from 270 to 200 Ma and has

removed 1-3 km of strata.

Very slow erosional event that took place and lasted from 200 to 100 Ma.

The paleo-geothermal gradient was approximately 22-27oC/km

With the exception of one partial study on basin analysis in the Gulf of St. Lawrence,

the various petroleum system parameters (the timing of hydrocarbon generation,

expulsion, and entrapment histories) of sediments from various basin and

subbasins of Cape Breton Island have not yet been evaluated (Rehill, 1996).

5. SAMPLES Based on the earlier petroleum system studies from Carboniferous sediments

from other subbasins of onshore Nova Scotia, Mukhopadhyay et al. (2000) has

documented the presence of the following petroleum system components within

various subbasins of Cape Breton Island:

Source Rock units: Lacustrine or fluvio-deltaic shales from the Horton Group of Upper

Devonian to Lower Carboniferous age (kerogen Type I, II, II-III, III) (example: Figures 12a[i] and 12a [ii]);

Marine shale and carbonates of the Windsor Group of Lower Carboniferous age (kerogen Type II, II-III, and III) (example: Figures 12b [i] and 12b [ii]);

Fluviodeltaic shales of the Mabou Group of Upper Carboniferous age (kerogen Type II-III and III) (example: Figure 12c);


43

Lacustrine and fluviodeltaic shale, coal, and coaly shale of the Cumberland Group of Upper Carboniferous age (kerogen Type I, II, II-III, and III) (example: Figure 12d).

Reservoir units: Fluvial and deltaic sandstones of the Horton Group (channel bodies, etc.)

(example: Figure 13a); Reef, breccia, and karsted carbonate rocks of the Windsor Group

(example: Figure 13b); Fluvial and deltaic channel Cumberland Group (Boss Point formation

equivalent) (example: Figure 13c). Seal beds:

Lacustrine shales of the Horton Group (example: Figures 12ai and 12aii); Salt and evaporite facies rocks of the Windsor Group (example: Figure 13d

and 13e); Fluviodeltaic shales of the Mabou and Cumberland Groups (Figure 12d).

Figure 13f (core samples from a Jubilee area) illustrates a mini-petroleum system

model showing a combination of dark carbonate source, oil-stained carrier

(anhydrite), oil-stained reservoir (fractured carbonate), and seal (anhydrite)

rocks. Based on the petroleum system parameters, core, cuttings, and outcrop

samples have been collected from various wells on Cape Breton Island (Tables 1

and 2). Figures 14a, 14b, and 14c (also Figures 3b and 5) illustrate the location

of analyzed samples from western Cape Breton, Central Cape Breton Subbasins,

and Sydney Basin (samples from Mukhopadhyay, 2000; under permission from

Total Inc. 2004; Figure 14C), respectively.

One hundred twenty-nine core, cuttings, and outcrop samples from the western

and central Cape Breton subbasins have been collected for the current contract

(Tables 2). Within these samples, only six samples have been collected from

various outcrops by Billy Shaw of W. G. Shaw & Associates Limited and Paul

Harvey from the Nova Scotia Department of Energy. All other samples have

been collected from the Stellarton Drill Core Library of the Nova Scotia

Department of Natural Resources. Figure 5 illustrates the location of all these


44

wells and outcrop samples (129 in total) that have been collected for this

contract. As the core and cuttings samples collected from various older wells for

this study (and also for Mukhopadhyay, 2000) are actually in feet, the real depths

in feet will be used in various chapters of this report in order to preserve original

depth intervals. However, Table 2 includes the depth intervals converted both in

feet and in metre.

In 2000, Global Geoenergy Research Limited has completed a contract report on

the geochemical evaluation and petroleum potential of the Sydney subbasin and

surrounding areas for Total Inc. (formerly of Total Fina Inc.). That report includes

an extensive source and reservoir rock evaluation of the Sydney Subbasin and

surrounding areas. Accordingly, eighty-three samples were analyzed for the

source rock and oil-stain geochemistry and ten samples for the porosity and

permeability. Based on a request from Global Geoenergy Research Limited,

Total Incorporated from Calgary, Alberta has extended their permission to Dr. P.

K. Mukhopadhyay in 2004 to release the data from the report of Mukhopadhyay

(2000) for the Sydney Basin and surrounding areas. Accordingly, a selected data

has been included within this report, which has been acquired from

Mukhopadhyay (2000) (see next paragraph for details).

The following is the data protocol of this report, which includes various data

collected from samples analyzed for this contract (Table 2) and from

Mukhopadhyay (2000) (with permission of Total Inc., 2004):

seventy-five (75) samples analyzed for total organic carbon

determination by Leco carbon Analyzer and analyzed as part of this

contract (Table 3);

fifty (50) samples of Rock-Eval pyrolysis that were analyzed as part of

this contract (Tables 2 and 3). Tables 3a, 3b, and 3c are selected

Rock-Eval pyrolysis data from the western Cape Breton Subbasins,

central Cape Breton Subbasins, and Sydney Basin, respectively. The

data included in Tables 3a, 3b, and 3c are either analyzed through this


45

contract (Table 3a and part of the Table 3b) or acquired from

Mukhopadhyay (2000) (part of Table 3b and all of Table 3c) with the

permission from Total Inc. (2004).

forty (40) samples (out of the seventyfive) have been analyzed for

vitrinite reflectance for this contract (Table 4a). Table 4b includes the

vitrinite reflectance data that has been acquired from Mukhopadhyay

(2000) with the permission from Total Inc. (2004).

four (4) oil-stain reservoirs (sandstone and limestone) have been

analyzed for wet chemistry (bitumen extraction and liquid

chromatography), gas chromatography (GC), gas chromatography

mass spectrometry (GC-MS) for this contract (Table 5a [i]). Their

biomarker integration results are shown in Tables 5b and 6a. Tables

5a (ii) and 6b are results from the wet chemistry, GC, and GC-MS and

their biomarker integration of samples from Mukhopadhyay (2000)

(permission from Total Inc., 2004).

ten samples were analyzed for porosity and permeability determination

for this contract (Table 7). Tables 7a, 7b, and 7c shows the data on the

physical properties of selected reservoir rocks from western Cape

Breton Subbasins, central Cape Breton Subbasins, and from Sydney

Basin, respectively. This data are either analyzed through this contract

(Table 7a and part of the Table 7b) or derived from Mukhopadhyay

(2000) (part of Table 7b and all of Table 7c) with the permission from

Total Inc. (2004).

6. ANALYTICAL RESULTS AND DISCUSSION 6.1. WESTERN CAPE BRETON SUBBASINS 6.1.1. Organic Richness, Source Rock Potential and Maturation Thirty-five (35) sediment samples from the Lake Ainsle-88-1, Mull River #1,

Saarberg-8-1, -8-3, and -8-4, Mary #1, Imperial Port Hood #1 and Imperial

Mabou #1 wells from the Mabou-Lake Ainslie subbasin or depocentre have been

analyzed for total organic carbon determination (TOC) (Tables 3 and 3a). Based


46

on worldwide source rock studies, the minimum threshold of TOC for a potential

source rock for a major hydrocarbon discovery was considered to be 0.5% for

shale and 0.3% for limestone (Tissot and Welte, 1984).

With the exception of three samples from Lake Ainsle-88-1 well, all other

samples from the Horton and Windsor Groups have less than 0.5% TOC content

suggesting a low hydrocarbon potential. Apart from the organic richness of a

source rock, the following geochemical parameters (from Rock-Eval pyrolysis

and vitrinite reflectance analysis) are also considered as significant to define

hydrocarbon potential: (i) the relationship between S2 values and high production

indices (from Rock-Eval pyrolysis; Table 3a) in relation to maturity; (ii) position of

various samples within (a) TOC vs S2 (Figure 15a); (b) hydrogen index vs.

oxygen index (Figure 15b); (c) Tmax vs. hydrogen index values (Figure 15c); and

(d) Tmax vs. production index values (Fig.15d), This data may suggest that most

of these sediments from the Horton and Windsor Groups are gas-prone Type III

source rocks, which have partially expelled and are currently depleted in

hydrocarbons. Organic petrographic studies show that most samples from the

Mull River, Mabou, Mary, and Port Hood wells contain abundance of recycled

vitrinite grains (Table 4). Based on TOC, Rock-Eval pyrolysis, and organic

petrography data, it is evident that a majority of the samples from all these wells

are non-source rocks. Only a few samples are considered as potential gas-prone

Type III source rocks. One Mabou Group sample from the Imperial Port Hood #1

well shows a TOC content of 0.5% and higher hydrogen index value indicating

some marginal gas and condensate potential (Table 3).

The Horton and Windsor Group samples in Lake Ainsle-88-1 well (a shallow core

hole; Figure 5) has more than 0.5% TOC content and higher organic richness

than all wells from its southern counterpart in Mabou-Ainslie subbasin or

depocentre (Tables 3 and 3a). The black shale at 23.5m (77ft) below the oil-

stained sandstone is an oil-prone Type II kerogen. Considering its maturity (0.62-

0.79%, Table 4), this Horton shale shows significant oil potential. The


47

geochemical parameters (TOC, S2 and hydrogen index values and VRo) of the

other two samples (one from the Windsor and one from the Horton Group)

suggest that the other two samples are gas and condensate prone source rocks.

With the exception of Mary #1 well, the vitrinite reflectance data in all three

studied wells (Mull River #1, Imperial Port Hood #1, and Imperial Mabou #1) in

the southern part of the Mabou-Ainslie subbasin are considered to be anomalous

(Table 4; Figure 16): (a) most of these sediments are considered as mature to

overmature for hydrocarbon generation; and (b) the lower part of the drilled depth

of these wells shows lower maturity compared to the middle part of the section

(Figure 16). This data may suggest presence of either an overthrust or some

structural repetitions (as suggested by Durling et al. 1995) of the Horton Group

within the southwestern part of Cape Breton Island . This data also suggests

higher heat flux within the Windsor and Horton Groups from the southern part of

the Mabou-Ainslie subbasin, which has produced mainly mature to overmature

sediments.

Considering the current data and that of and Hamblin’s (1989) data on source

rock samples (for interpretation see Chapter 4.3.1.1 of this manuscript;

Appendices C-1a and C-1b), samples from all formations of the Horton Group

indicate mainly nonsource rocks with minor contributions from Type III and gas-

prone source rocks. Only sporadic sediments of the Horton Group from the

northern part of the Mabou-Ainslie subbasin are typical oil-prone (Type II), which

may have generated and expelled the crude oil into neighbouring Horton and

Windsor reservoir rocks.

The limited data from the earlier work of Mukhopadhyay (1991) may suggest that

the quality of the source rocks from these two groups in this region may improve

in the shallower part of the Gulf of St. Lawrence or St. Georges Bay and Lake

Ainsle area. It may be assumed that the quality of the oil-prone source rocks

(organic-rich black shale) similar to Albert Formation in New Brunswick and


48

mainland Nova Scotia (Shubenacadie or Windsor Sub-basins) of the Middle

Horton Group (Strathlorne Formation) may improve in the basinal part of the

Mabou-Ainslie subbasin. The Horton and Windsor Group source rocks in the

south of the Mabou-Ainslie depocentre (subbasin) are either overmature or

selectively gas-prone and have low hydrocarbon potential. Considering the

relationship between the Tmax data and production indices, it is evident that

samples from the northern part contain some autochthonous crude oil, whereas

samples from the southern side may contain migrated hydrocarbons possibly

from distal sources.

Considering the earlier work from Allen (1998), Mukhopadhyay (1991), and coal

data from the Geological Survey of Canada, Atlantic, the source rocks from the

Mabou and Cumberland Groups on Western Cape Breton Island are mainly

kerogen Type II-III and III and are considered to have major potential for gas and

condensate (Appendices C-2a to C2d and C-3a and C-3b). The gas seeps in this

region may support this concept. Accordingly, southern part of the Mabou-Ainslie

subbasin (Mull River #1 well and to the south), the upper Carboniferous

sediments of the Mabou and Cumberland Group have definite potential for gas

and condensate, which is lacking in the lower Carboniferous source rocks.

6.1.2. Genesis of Crude Oil or Bitumen It is interesting to observe that the Horton or Windsor Group sediment cores

(reservoir or source rock) from the Imperial Mabou #1 and Imperial Port Hood #1

do not show any oil-stains or asphaltene or pyro-bitumens. On the other hand,

almost all reservoir sandstone cores of various wells from the Lake Ainslie area

are stained with crude oil. Only one oil-stained sandstone from Lake Ainsle-88-1

well (sample no. 53; Table 2) has been analyzed within this contract for a

detailed geochemical evaluation.


49

6.1.2.1. Bitumen Extraction and Liquid Chreomatography (Table 5a)

The solvent extraction indicates that the yield of extractable organic matter (EOM

or bitumen) in this sample is high (12395 ppm) or (63.8% of TOC). This data

suggests that the sample is oil-stained as the EPOC (extract percent per gram of

organic carbon) values above 15% are generally indicative of either oil-stain or

contamination. Liquid chromatography (fractionation) analysis of the sample

shows that the sample is rich in saturated and aromatic hydrocarbons (33.7%

and 18.1%, respectively; Figure 17).

6.1.2.2. Gas Chromatography of the Saturate Fraction (Figure 18)

The sample shows a broad pattern with a large amounts of unresolved complex

mixture (UCM, or hump) appearing between 40 and about 70 minute RT

suggesting biodegradation of this oil. A pristane/ phytane ratio of 0.77 calculated

for this oil is consistent with a reducing depositional environment.

6.1.2.3. Gas Chromatography Mass Spectrometry

Both tricyclic and pentacyclic terpanes including long chain homologues C27 up to

C35 hopanes are detected in this bitumen (Figure 19a). C29- and C30- moretanes

are abundant, and the concentrations of the 22S extended hopane isomers are

greater than that of the 22R isomers, giving a 22S/(22S+22R) C32 ratio of 0.59

consistent with the intermediate oil window (Figure 19b). C29 18α (H)-

norneohopane (C29Ts) and C30 17α(H)-diahopane (30* compound) are present in

low abundance, showing a C30*/C29Ts ratio of 0.60 (Figure 17c) suggesting that

hydrocarbons in this sample are derived from a source rock deposited in a

nonmarine, dystrophic environment (between oxic and anoxic). Gammacerane (a

C30-triterpane) is moderately abundant in this bitumen (Figure 19a), showing a

relatively low gammacerane ratio of 0.18 (Figure 19d) indicative of nonmarine

depositional environment. The sterane (m/z 217) mass chromatogram of this

bitumen (Figures 19d and 19e) shows relatively high abundances of C29 5a, 14a,

17a steranes (ααα-steranes) and αββ-steranes relative to those of C27 and C28 ,

suggesting a large input of terrigenous organic matter (a support for nonmarine


50

environment). The value of C29 ααα 20S/(S+R) ratio computed for this sample

(0.47) suggests a maturity level equivalent to intermediate oil window (light blue

traingle in Figure 19b).

Based on the biomarker fingerprinting, the oil stain in the shallower reservoir from

the Lake Ainslie 88-1 well is biodegraded and derived from a reducing lacustrine

depositional environment.

6.1.3. Reservoir Quality: Porosity and Permeability Five sandstone reservoirs from the Horton Group and one carbonate reservoir

from the Windsor Group have been analyzed for porosity, permeability, and grain

density measurement. Figures 4, 5 and 14a show the location of these samples.

This data suggests that all reservoirs have more than 10% porosity, but the

permeability data is highly variable. The outcrop sandstone sample at location 3

within the Ainsle depocentre has an extremely high permeability (105.1 mD).

Other two outcrop sandstone samples (locations 14 and 19) from the Mabou-

Ainsle subbasin also have somewhat high permeability (14.1mD and 8.2 mD,

respectively). All other samples have less than 1 mD permeability. This data

suggests some excellent reservoir potential of Horton Group sediments within the

northern part of the Mabou-Ainsle subbasin.

6.2. CENTRAL CAPE BRETON SUBBASINS: CURRENT + EARLIER DATA (PERMISSION FROM TOTAL INC.) The complete lithostratigraphy of the Windsor Group from the Central Cape

Breton Island is also illustrated in Figure 6b (after P. Giles, personal

communication, 2000). It illustrates the cyclic deposition of the Windsor

sediments that includes the deposition of anoxic black limestone and calcareous

shale at the lowermost, in the middle, and in the upper part of the Windsor Group

(P. Giles, personal communications, 2000; Boehner and Giles, 1993).


51

6.2.1. Organic Richness, Source Rock Potential and Maturation The analyzed samples have been collected mainly from two subbasins of Central

Cape Breton Island (Loch Lomond subbasin, Bras D’Or subbasin (including

Orangedale, Malagawatch, and Jubilee areas). A majority of these sediments

have been chosen from the Windsor Group with a few from the Mabou and

Cumberland groups. No samples from the Horton Group were analyzed from

these two subbasins. Compared to the Mabou-Ainslie subbasin, a majority of the

samples have more than 0.5% TOC. Some of the samples from both subbasins

have more than 1.5% TOC (Tables 3, 3b, and 3c; example: well M-5A – 460m;

Table 3b). The source rock quality (S2 vs. TOC; Figure 20a), source rock

potential (hydrogen index vs. oxygen index [Figure 20b] and Tmax vs. hydrogen

index [Figure 20c]) diagrams show the presence of mature oil-prone source rocks

within most of the areas. This data also suggest that abundant gas and

condensate-prone source rocks are also present. The Tmax vs. production index

diagram and high S1 values in various source rocks may suggest abundant in-

situ oil generation and expulsion from various source rocks, mainly from the

Windsor Group (Figure 20d).

The vitrinite reflectance data suggests that the projected surface maturity of the

Windsor Group of sediments varies between 0.5 to 0.7% Ro (Figure 21). This

data is also confirmed by the earlier studies of Mukhopadhyay (1991) (Appendix

C-2e) and TAI data from Utting and Hamblin (1991). With the exception of

Cleveland 227-2 well, the maturity gradient of ten wells from the Central Cape

Breton Island indicates that all these sediments lie within the principle phase of

oil generation (0.7 to 1.0% Ro) (Figure 21). Some of the examples of these wells

are: M-5A, M-9, Bras d’Or 9-78, Loch Lomond -04, etc.; data of two wells [McIver

Pt. #1 and Cerro Mining #7] within these ten wells are acquired from Total Fina

contract (Mukhopadhyay, 2000). This data may suggest that Central Cape

Breton subbasins have lower and less anomalous thermal gradient compared to

the southern part of the Mabou-Ainslie subbasin.


52

In summary, the organic richness and source rock potential of most of these dark

carbonates (especially some from the Macumber Formation) have an excellent

liquid hydrocarbon (crude oil and condensate) potential. Additionally, the thermal

history of these sediments from the Malagawatch-Bras d’Or, Jubilee, and Loch

Lomond areas may have lower structural deformation (at least within the Windsor

Group) compared to the southern part of the Mabou-Ainslie subbasin and the

western part of the Bras-d’Or subbasin

Anomalously high S1 and production indices (PI) of some of the Windsor Group

carbonates may open up two possibilities (Table 3b [ii]): hydrocarbons are either

derived as in-situ generation (autochthonous) similar to various other carbonate

source rocks from other carboniferous basins or as migrated oil (allochthonous)

from other sources. However, the high TOC values and the presence of high S2

values in some of the sediments suggest that the stained oil is derived from an

autochthonous source. Accordingly, an early generation, primary migration and

redistribution of hydrocarbons have occurred within the kerogen matrix of most of

the Windsor Group candidate source rocks, The analyzed samples that have

TOC values lower than 0.3% but contain high S1 and PI values, indicate the

presence of migrated hydrocarbons.

Considering the source rock potential and hydrocarbon expulsion of the source

rocks, the possible biohermal play types within the Windsor Group, the Jubilee

and Malagawatch areas may have the best potential for an oil discovery.

6.2.2. Genesis of Crude Oil and Oil-Source Rock Correlation Three oil stained samples have been analyzed for this contract (Table 2).

However, another four samples of source rocks, oil-stained limestone reservoir,

and crude oil (Malagawatch M-9 well) have also been included from the Total Inc.

contract (Mukhopadhyay, 2004) (not shown within Table 2). Accordingly, a total

of six source rocks or oil-stained carbonates (mostly from the Windsor Group)


53

and one crude oil sample from the Central Cape Breton subbasins have been

analyzed for detailed geochemical methods.

6.2.2.1. Solvent Extraction and Fractionation Results

Current Contract

The solvent extraction of the current samples from AGT-34-77 (357.2ft or

108.9m; sample no. 3; Table 2), M-3 (1104m; sample no. 35; Table 2), and LL-04

(196.48m; sample no. 41; Table 2) wells indicate that the yields of extractable

organic matter (EOM or bitumen) are moderately high (between 1976 ppm and

3618 ppm). The extract as a percentage of total organic carbon (EPOC) values

calculated for the samples investigated are 79%, 6.4%, and 6.8% respectively.

This data suggests that samples from the Malagawatch M-3 and LL-04 (Loch

Lomond) wells contain in- situ bitumen. On the other hand, sample from the

limestone reservoir from Jubilee ATG-34-77 well appears to be oil-stained. Liquid

chromatography (fractionation) analysis indicate that the bitumen in the AGT-34-

77 and Malagawatch M-3 samples are rich in saturated and aromatic

hydrocarbons (saturates: 57.9% and 31.4%; aromatics: 18.1% and 33.7%

respectively), whereas the LL-04 sample is rich in aromatics (55.6%). Figure 17

shows the position of these samples

Total Fina Contract (Mukhopadhyay, 2000)

One source rock (McIvor Pt R#1 [sample 68; from Mukhopadhyay, 2000; not

from Table 2]) and two stained source-reservoir rocks (ATG-17-77, 218ft, sample

61; from Mukhopadhyay, 2000; not from Table 2); McIvor Pt R#1, 896ft, sample

71 ) from the Windsor Group have been analyzed. All these samples have high

extract yields (>1000 ppm; Tables 5a and 5b). Sample 61 has the highest

bitumen extract yield (4214 ppm), whereas two other source and reservoir rocks

(sample 68 and sample 71) have low to moderate extraction yields (145 and 768

ppm). In contrast to the crude oil sample from the Malagawatch M-9 well (number

84; 33 API; courtesy of Peter Giles, 2000), all other samples contain relatively

higher polar compounds (NSO and asphaltene). The relative proportions of


54

hydrocarbons (saturate and aromatic compounds), resins, and asphaltenes have

indicated that with the exception of crude oil from Malagawatch M-9 well, all

rocks have less than 50% hydrocarbons of total extracts for these samples. The

relatively high saturate/aromatics ratio has been observed on both oil-stained

reservoirs (samples 61 and 71) and in crude oil. Two limestone samples from the

McIvor Pt. R#1 well (numbers 68 and 71 of Mukhopadhyay, 2000 and not from

Table 2) are considered to be source and reservoir rocks, the plot within the

ternary diagram shows that these two samples (68 and 71) have similar

composition (Figure 22).

6.2.2.2. Gas Chromatography of Saturate Fractions

Current Contract

The alkane distributions of the saturate fraction of the extract bitumens (Figure

23) indicates the following

• Sample at AGT-34-77 well (218m) shows a hump in the n-C12 to n-C42

region with n-alkanes above C21 representing the most abundant

components (Figure 23a [i]). The low pristine/phytane ratio of 0.19 is

indicative of hydrocarbons derived from a Type II kerogen derived from

anoxic marine environment (possibly evaporatic) (Table 5a [i]).

• The normal alkanes at Malagawatch M-3 well (1104m) show a broad

distribution pattern in the range of n-C12 to n-C33, with n-alkanes between

C12 and C20 are abundant (Figure 23a [ii]). Pristane and phytane are

moderately abundant, showing a pristane/phytane ratio of 2.13, consistent

with a dystrophic (oxygen-poor) depositional environment with moderate

input (or contribution) of terrigenous materials (Table 5a [i]).

• Sample at LL-04 well (196ft) reveals an alkane distribution pattern in the

n-C11 up to n-C33, with n-alkanes between C19 and C25 showing an odd-

over-even predominance (Figure 23a [iii]). This sample shows an

anomalously high abundances of isoprenoids (i-C14 to i-C20 or phytane), as

well as the hump appearing in this GC between 35 and 60 min. Retention


55

time (RT) is probably attributed to the biodegradation. Pristane is strongly

abundant and dominant over phytane showing a pristane/phytane ratio of

1.7. The alkane fingerprint of this sample is characteristic of hydrocarbons

generated at marginal maturity level from a source rock rich in humic

organic matter. This finding can be further supported by the ratios of

pristane /n-C17 and phytane/n-C18 (Table 5a [i]).


The GC-FID traces of the oil and extracts are all distinctly different (Figures 23b,

23c, 23d, and 23e; Table 3b). Source rock, maturity differences, and varying

levels of biodegradation may be the controlling factors for these differences. The

gas chromatogram of sample 68 (McIver Pt. #1, 45.7m or 149.7ft; Table 3b)

indicates depletion in normal alkanes and elevated chromatographic baselines

("hump" due to the unresolved complex mixture of hydrocarbons) showing clear

evidence of biodegradation.

Significantly, the relative amounts of pristane and phytane appear to provide a

more reliable line of evidence. The pristane/phytane ratios of both oil (sample 84)

and the oil-stained rock from ATG-17-77 well (sample 61) are very low,

suggesting a highly reducing (carbonate?) depositional environment. In contrast,

the pristane/phytane ratios for the other two extracts from the McIver Point #1

well are all above 1.0. This data may suggest that these source rocks have

originated from a mixed depositional environment.

A cross-plot of the pristane/n-C17 and phytane/n-C18 ratios suggests that the

Malagawatch crude oil sample (no. 84) and extract from the Jubilee well (ATG-

17-77; sample no. 61) are derived from marine organic matter (OM), which are

deposited under strongly reducing conditions (Mukhopadhyay, 2000). On the

other hand, the two other bitumen extracts from the McIver Pt #1 well (samples

68 and 71) show a mixture of marine and terrestrial organic matter. Extract of

sample 68 suggests that the advanced biodegradation may have changed the


56

ratios and its position in this diagram as the isoprenoid/normal alkane ratio tend

to be elevated for biodegraded samples.

6.2.2.3. Gas chromatography-Mass spectrometry (GC-MS) of biomarkers

Saturate fractions of the three selected stained oil and bitumen from the current

contract and one source rock, two oil-stained reservoirs rocks, and one crude oil

from the Total Fina contract have been investigated for their biological markers

(steranes, tricyclic/pentacyclic tepanes). The study of these biomarkers is based

on distribution patterns of the key ions m/z 191 (triterpanes), m/z 217 (steranes)

monitored during the selected ion monitoring (SIM) runs of the GC-MS

(Appendices 1 and 2). A set of other ions have been monitored during each SIM

run, but only m/z191 and m/z 217 will be discussed in this report, while the other

monitored key ions were mainly used to identify the unknown compounds and

calculate numerous biomarker ratios.

Current Contract

Oil-Stained Windsor Carbonate from ATG-34-77 well at 108.9m (357ft):

Both tricyclic terpanes and pentacyclic triterpanes, including long chain

homologues C27 up to C35 hopanes are detectable in this bitumen (m/z 191 mass

chromatogram in Figure 24a). In this bitumen, the C29- and C30- moretanes are

present in very low abundances, and the concentrations of the 22S extended

hopane isomers are greater than that of the 22R isomers, giving a

22S/(22S+22R) C32 ratio of 0.56 consistent with the peak oil window (Figure

19b). Earlier studies have indicated that samples showing 22S/ (22S+22R) C32

ratios in the range of 0.50 to 0.54 indicate early oil generation stage, while ratios

in the range of 0.55 to 0.62 suggest the main phase of generation (Peters and

Moldowan, 1993).

Terpanes chromatogram of this bitumen reveals the presence of C29 18α (H)-

norneohopane (C29Ts) and C30 17α(H)-diahopane (30* compound) yielding a

C30*/C29Ts ratio of 0.78 (Figure 19c). It appears that relative amounts of 30* and


57

C29Ts depend most strongly on the environment of deposition (Peters and

Moldowan, 1993). Oils and bitumen derived from clay-rich shales deposited

under oxic-suboxic conditions show higher C30*/C29Ts ratios than those (such as

the sample AGT-34-77) derived from source rocks deposited under anoxic

conditions (Moldowan et al., 1991) (Fig.19c).

Gammacerane (a C30-triterpane) is moderately abundant in the bitumen from the

Jubilee well (Figure 24a), showing a gammacerane ratio (gammacerane/C30-

hopane) of 0.21 (Figure 19d). Gammacerane represents a marker for highly

saline possibly lacustrine (in this case) depositional environments (Hunt, 1995).

Although oils and bitumens with high gammacerane ratios can often be traced to

hypersaline depositional environments, these environments do not always result

in high gammacerane ratio (Moldowan et al., 1985).

The sterane (m/z 217) mass chromatogram of this bitumen (Figure 24a) shows

moderate abundances of C27 and C29 5a, 14a, 17a steranes (ααα-steranes) and

αββ-steranes. Both the lack of C30-steranes, and low C25/C26 tricyclic terpane

ratio (< 1) observed in this samples (Figure 19e) are typical of nonmarine

(possibly lacustrine) source rocks (Zumberge, 1987; Burwood et al., 1992). The

C29ααα 20S/(S+R) ratio computed for the C29 steranes is commonly used as a

reliable thermal maturity indicator (Peters and Moldowan, 1993). The value of

this ratio calculated for this sample (0.51) is consistent with the hopane maturity

(Figure 19b) suggesting a maturity level equivalent to the peak oil window.

Organic matter type is evidently the major factor controlling the sterane carbon

number distributions. Therefore, a C27-C28-C29 sterane ternary diagram is

commonly applied for interpreting the source input and depositional environment

(Peters and Moldowan, 1993) (Figure 19f). Sterane ternary diagrams are used

extensively to show relationship between oils and/or source rock bitumens,

because plot locations on these diagrams do not significantly change throughout

the oil-generative window (Peters and Moldowan, 1993). A high abundance of


58

C29 steranes is generally expected to occur in oils and/or source rock bitumens

derived mostly from terrigenous (humic or lacustrine) organic matter.

The sterane carbon number distribution of sample ATG-34-77 (Figure 19f) shows

moderate abundances of C27- and C29- steranes. Such a sterane carbon number

distribution pattern is characteristic of hydrocarbons generated predominantly

from sapropelic compounds (Type II kerogen). All this data indicates that this oil

staining within the fractured carbonate rocks from the Windsor Group may

possibly be derived from a mixture of lacustrine (Horton Group) and marine

(Windsor Group) source rocks.

Oil-Soaked Windsor Carbonate at Malagawatch M-3, 1104.4m (sample No. 35):

Both tricyclic terpanes and pentacyclic triterpanes are detectable in this bitumen

(m/z 191 mass chromatogram in Figure 24b). Very high abundances of tricyclic

tepanes, supported by the dominance of the 22S extended hopane isomers over

that of the 22R isomers {22S/(22S+22R) C32 ratio of 0.62} is consistent with peak

oil window (Figure 19).

The M-3 bitumen reveals significant abundances of C29 18α (H)-norneohopane

(C29Ts) and C30 17α(H)-diahopane (30* compound), showing a high C30*/C29Ts

ratio of 2.2 (Figure 19c) indicative of hydrocarbons derived at least partly from a

clay-rich source rock deposited under suboxic conditions.

Gammacerane (a C30-triterpane) is present in very low concentration (Figure

24b), showing a very low gammacerane ratio (gammacerane/C30-hopane) of 0.11

(Figure 19d). Low gammacerane ratio calculated for this bitumen is inconsistent

with a hypersaline depositional environment.

The sterane (m/z 217) mass chromatogram of this bitumen (Figure 24b) shows

relatively high abundances of C27 and C29 5a, 14a, 17a steranes (ααα-steranes)

and αββ-steranes. The value of C29 ααα-20S/(S+R) ratio computed for this


59

sample (0.62) is consistent with the hopane maturity (Figure 19b) suggesting a

maturity level equivalent to the peak oil window or slightly higher. This data

corroborates the vitrinite reflectance data for this depth from Malagawatch 5A

and Malagawatch M-9 wells (Table 3b).

The sterane carbon number distribution of sample M-3 (Figure 19f) shows



from sapropelic marine (Type II kerogen), with a minor input of terrigenous

material. All the above saturate biomarker data indicates that this oil staining

within the fractured carbonate rocks from the Windsor Group was derived mainly

from a marine source rock from the Windsor Group deposited in dysoxic

condition. However, terrestrial organic matter within the Windsor Group may

have also contributed a part of the hydrocarbons. Incidentally, the organic

petrology data of some of the Windsor Group marine source rocks (kerogen Type

II-III) from Malagawatch M-5A well shows presence of the abundant terrestrial

organic matter.

Bitumen-impregnated Windsor Carbonate at Loch Lomond-04 well: Both tricyclic

terpanes and pentacyclic triterpanes, including long chain homologues C27 up to

C35 hopanes are detectable in this bitumen (Figure 24c). C29- and C30- moretanes

are in very low abundance, and the concentrations of the 22S extended hopane

isomers are significantly greater than that of the 22R isomers, giving a

22S/(22S+22R) C32 ratio of 0.60 consistent with the peak oil window (Figure

19b).

C29 18α (H)-norneohopane (C29Ts) and C30 17α(H)-diahopane (30* compound)

are present in fair to moderate abundances, showing a C30*/C29Ts ratio of 2.3

(Figure 19c) suggesting that hydrocarbons in this sample are derived from clay-

rich source rocks deposited in an oxic-suboxic depositional environment

(Moldowan et al., 1985)..


60

Gammacerane (a C30-triterpane) is strongly abundant in this bitumen (Figure

24c), showing a relatively high gammacerane ratio (gammacerane/C30-hopane)

of 0.60 (Figure 19d). High gammacerane ratios (such as that observed in sample

LL-04) can often be traced to hypersaline (or lacustrine) depositional

environments (Moldowan et al., 1985).

The sterane (m/z 217) mass chromatogram of this bitumen (Figure 24c) shows

relatively high abundances of C27 and C29 5a, 14a, 17a steranes (ααα-steranes)

and αββ-steranes. The value of C29 ααα 20S/(S+R) ratio computed for this

sample (0.51) is consistent with a high maturity level equivalent to the peak oil

window (Figure 19b). Vitrinite reflectance data for these samples from the same

well also supports the calibrated maturity.

The sterane carbon number distribution of sample LL-04 (Figure 19f) shows



from sapropelic (Type II kerogen) with minor input of terrigenous material.

The high gammacerane ratio and abundance of C29 hopanes suggest that the oil

stain within the Windsor carbonate rock is possibly derived from mixed Windsor

Group marine carbonate and hypersaline terrestrial shale from the Horton or

Mabou Group.


Table 6b illustrates the semi-quantitative area percentages of various

compounds within triterpane (m/z 191) and sterane (m/z 217) groups. Figures

24d (i), 24e (i), 24f (i), and 24g (i) show the mass chromatograms of triterpanes

for samples 61 (Jubilee well extract), 68 and 71 (McIver Pt #1 well extracts), and

84 (crude oil, Malagawatch M-9 well), respectively. Figures 24d (ii), 24e (ii), 24f

(ii), and 24g (ii) show the mass chromatograms of sterane distributions for


61

samples 61 (Jubilee well extract), 68 and 71 (McIver Pt #1 well extracts), and 84

(crude oil, Malagawatch M-9 well), respectively.

Samples 68 and 71 (both from the McIver Pt #1 well) also closely resemble one

another in their terpane distributions. Similarly, these two samples closely

resemble each other in the sterane distributions. They have relatively more C27

regular steranes than samples 84 (crude oil) and 61 (oil-stained carbonate), with

C29 to C27 ratios of about 3/2, as well as regular and rearranged steranes in

approximately equal proportions. Both samples have relatively high diasterane

content than the regular sterane indicating both higher maturity and variable

biodegradation.

The most striking feature of oil sample 84 (Malagawatch M-9 well) is the strong

predominance of tricyclic terpanes, notably including the extended tricyclics.

None of the other three extracts exhibits such an extreme predominance of

tricyclics; however, Sample 61 has reasonably abundant tricyclics, including the

long-chain. The tricyclic/pentacyclic terpane distributions of Sample 61 (from

Jubilee well) and 84 (crude oil) have many commonalties, which are indicative of

genetic similarities, in spite of maturation differences. Oil sample 84 is

characterized by a preponderance of C29 regular steranes and a lack of C27. It is

also strongly depleted in diasteranes.

By considering the relative proportions of steranes, hopanes and tricyclic

terpanes, it is apparent that none of the two other extracts from the McIver #1

well exhibit the extreme tricyclic enrichment of oil sample 84 and sample 61. The

carbon number distributions of tricyclic terpanes, which are fairly immune to

thermal alteration, provide further details useful in the correlation exercise. A

ternary diagram featuring short, medium and long-chain tricyclics shows a

clustering of samples 61 and 84 (oil sample), distinguished by 35-50% long-chain

tricyclics. The remaining two samples also cluster together and are characterized

by the depletion in the larger compounds.


62

A principal component analysis of the available GC-FID, m/z 217 and 191 data

from these four samples indicates that the long-chain tricyclic terpanes and

phytane are particularly important compounds for distinguishing various samples.

This may be summarized concisely by cross-plotting the %C28+ tricyclic terpanes

(relative to all tricyclics) versus the pristane/phytane ratio (see Mukhopadhyay,

2000).

Extracts 68 and 71 are relatively enriched in the C27 18αH-trisnorhopane (Ts,

peak L), C29 18αH-norneohopane (29Ts, peak S), C30 17αH diahopane (peak T),

as well as the C24 tetracycline terpane (peak H). Moreover, a high

hopane/sterane ratio in samples 68 and 71 is indicative of a strong terrestrial

influence (Table 6b). On the other hand, samples 61 (Jubilee well) and 84 (crude

oil) have quite low pristine/phytane and hopane/sterane ratios, enrichment in

long-chain tricyclics, and moderate gammacerane (peak c). This data has clearly

indicated that both samples 61 (oil-stained source rock) and 84 (crude oil) have

been derived from a marine carbonate source. Considering the abundance of

C27, C28, and C29 steranes of these samples, the oil sample and sample 61 falls

within the marine carbonate oil zone (Hunt, 1995) and other two (68 and 71) may

have been derived mainly from a terrestrial source within minor contributions

from a marine source (Mukhopadhyay, 2000).

The maturity of these four samples have been evaluated from the Ts/Tm ratio,

percentages of C30 moretane, and 22S/(22S + 22R) C31 hopanes. Accordingly,

the crude oil and the sample 71 have a maturity between 0.7 and 1.0% Ro

equivalent, whereas samples 61 (Jubilee well) and 68 (McIver Pt #1) has been

derived from a source rock between 0.5 and 0.7% Ro supporting the measured

Ro data.

6.2.3. Reservoir Analysis: Porosity and Permeability

Table 7b illustrates the data for a total of six samples (four from the Windsor

Group; one each from both Mabou and Cumberland groups) from the Central


63

Cape Breton subbasins. Two Windsor Group carbonate samples (sample

numbers 13 and 30) are selected from the current contract collection, while the

other two are from the Total Fina contract (Mukhopadhyay, 2000). These

samples were taken from the Orangedale 225-5A, Malagawatch M-7, Loch

Lomond LL-04, Loch Lomond Imperial 30-4, and Loch Lomond LL-1-91 wells.

All analyzed six samples have permeabilities less than 1 mD. On the other hand,

with the exception of Malagawatch M-7 well sample, all other samples have more

than 4% porosity (4.1 to 15%) (Table 7b). The lack of high permeability

carbonate reservoir within our analyzed samples is possibly due to lack of

selection of proper core samples from most of these wells (especially from the

Malagawatch-Bras D’Or subbasin). A more detailed study of the physical

properties of typical fractured reef carbonate reservoirs from these subbasins is

required in the future. This reef carbonate could be similar to some selected

sample analyzed for the Sydney subbasin (Table 7c).

6.3. SYDNEY BASIN 6.3.1. Organic Richness, Source Rock Potential and Maturation

As discussed earlier, a total number of 63 samples (28 from two offshore wells)

have been analyzed for total organic carbon (TOC) and 41 samples for Rock-

Eval pyrolysis (Table 3c). The range of TOC values for various stratigraphic

intervals is as follows:

The Mid-Devonian Pre-Horton sediments from the McAdams Lake area vary

between 1.67 to 9.28%.

The Grantmire Formation of the Horton Group from the two offshore wells (N.

Sydney P-05 and F-24) and one sample each from the Horton Group in Pt.

Edwards-84-1 (PT-84-1) wells varies between 0.03 and 0.37% (Figure 14c).

The Windsor Group sediments have TOC content between 0.1 to 2.12%.

Both high and low TOC values were derived from the Woodbine Road 84-1

[WR-84-1] well.


64

The grey to black shales from the Mabou Group vary between 0.31

(Woodbine Road [WR]-84-1) to 2.58% in N. Sydney F-24 although the

sandstone from this group has TOC value of 0.04% (Figure 14c).

The coal, coaly shale, and gray shale from the Cumberland Group have

between 0.93 (well: Kempthead [KH]-84-1; Figure 14c) to 77.15% (N. Sydney

F-24).

Once again, the minimum threshold of TOC was considered to be 0.5% for shale

and 0.3% for limestone (Tissot and Welte, 1984). Accordingly, a majority of the

Windsor Group limestone has more than the threshold value for hydrocarbon

generation and expulsion.

The range of S2 (mg HC/g rock) and hydrogen index (HI) (mg HC/g TOC) data

for various stratigraphic intervals is as follows (Table 3c):

o In the Mid-Devonian Pre-Horton sediments from the McAdams Lake area,

they vary between 0.21 to 6.6 and 13 to 71, respectively,

o The Grantmire Formation of the Horton Group has only one (N. Sydney F-

24, 1694.7m) analytical data because of the low TOC content of these

sediments. This data shows a S2 and HI values of 0.1 and 27,

respectively,

o The Windsor Group sediments range in values 0.03 to 14.19 and 12 to

904. The lowest and highest values are from the WR-84-1 well (550.5m)

and KH-84-1well (112.5m), respectively,

o The gray to black shales from the Mabou Group vary between 0.2 (Pt.

Edwards-84-1) to 1.7 (N. Sydney F-24) for S2 and 42 to 89 for HI,

o The coal, carbonaceous shale, and gray shale from the Cumberland

Group range from 0.21 (KH-84-1) to 71.52 (N. Sydney F-24) for S2 and 23

to 218 for hydrogen indices (N. Sydney P-05),

o One sample from the Pictou Group in the N. Sydney F-24 well has TOC:

3.15%; S2: 2.19; and HI = 70,

o A plot of TOC versus S2 shows that a majority of the analyzed samples

have hydrocarbon potential (both gas and oil) (Figure 25a).


65

Two source rock potential diagrams (hydrogen index versus oxygen index

[Figure 25b] and Tmax versus hydrogen index [Figure 25c] indicate the

following:

Two calcareous shale samples from the Windsor Group of the

Kempthead [KH]-84-1 from the Windsor Group well lie within oil-prone

Type I kerogen maturation path

Six other samples (all three from the Ingonish wells, one each from

Woodbine Road [WR]-84-1 and two from the North Sydney P-05 well) are

oil and condensate-prone source rocks

A vast majority of other samples are gas-prone Type III kerogen

The source rock characterization of these sediments suggests that the black

limestone and calcareous shale of the Windsor Group (Macumber and Woodbine

Road formations) and coal or oil shale from the Morien Group (Cumberland

Group) have major potential for liquid hydrocarbon generation. Earlier studies by

Global Geoenergy Research Limited on the black shales from the Mabou Group

(Cape Dauphin Formation) and coal/carbonaceous shales from the Morien Group

of Point Aconi and Sydney Mines have suggested that these source rocks have

major potential for the generation of natural gas and condensate. The sediments

from the Horton (Grantmire Formation) and Pictou Groups could not be

evaluated properly due to the lack of available samples.

A plot of Production Index versus Tmax shows that fifty percent of these liquid

hydrocarbons within these sediments in the Sydney Basin are within the principle

phase oil expulsion and the other 50 percent lie within the gas and condensate

zone (Figure 25d). Accordingly, it is suggested that about 50% of the liquid

hydrocarbons already present within these source rocks (S1 fraction) have been

derived in situ.


66

Based on the measured vitrinite reflectance, all samples lie within the so-called

“oil window” (0.5 – 1.35% Ro) (Table 4b). The maturity at various depths has

been illustrated for seven wells: five onshore wells from various locations (Figure

26a) and two offshore wells from North Sydney (Figure 26b). The vitrinite

reflectance values from the two offshore wells (North Sydney F-24 and P-05) that

were drilled very close to a major fault zone show an anomalous trend (Figure

26b). The sediments from 0 to 1000m show a rapid increase in vitrinite

reflectance from 0.5 to 0.85% Ro, whereas sediments between 1000 to 1700m

show very little increase in maturity. The fluorescent characteristics clearly

suggest that sediments at the bottom of wells N. Sydney F-24 and P-05 are still

within the so-called “oil window”, which definitely ruled out the presence of

overmature rocks as defined both by Robertson Research (1974,1976) and

Hacquebard (1976).

A similar anomalous maturity profile has also been observed within the St. Paul

P-91 by Petro-Canada. The St. Paul P-91 well was drilled very close to another

major fault system (Hollow Fault zone). Mukhopadhyay (1991) has observed that

the maturity of the onshore sediments from the Horton Group has been affected

drastically close to a major fault system. In general, the Ro values of sediments

within 1-3 km of a major fault have been anomalously increased compared to the

sediments >3 km away from the fault. This data and other evidences suggest

that the fault zones are the conduits of major hot oxidizing fluid movement in

most parts of onshore Nova Scotia especially in the Sydney Basin

(Mukhopadhyay, 1991; Mukhopadhyay et al., 2000). Therefore, the sediments

from both North Sydney F-24/P-05 and St. Paul P-91 wells may have been

affected by the high-temperature hydrothermal fluid flowing through a major fault.

The high maturity trend of Birch Grove #1 (onshore well) as observed by

Hacquebard (unpublished Geological Survey of Canada unpublished data) may

also be related to both surface oxidation and high-temperature brine movement.

From the interpretation of Hacquebard (unpublished data) and Mukhopadhyay et


67

al (2000), a lower maturity below this zone of sediments could be expected away

from the fault zone in offshore Sydney subbasin.

The maturity trends of five onshore wells show the following characteristics

(Figure 26a):

The sediments from Mid-Devonian age (Pre-Horton) have higher thermal

gradients than the younger units up to Mabou Group.

Low thermal gradients (0.08% Ro/100m) were observed in most wells.

The maturity of most coal samples in the Morien Group could be partially

oxidized. Therefore, these coals have higher maturity than the

corresponding carbonaceous shales from the Morien Group similar to

other basins of the world (Mukhopadhyay, 1992). The coal seams have

higher maturity than even the shales and carbonates from the Mabou and

Windsor Groups in some of the wells. A typical example is the NC-87-1

well where the reflectance of the coal seams is higher than the shales

(Figure 26a).

6.3.2. Characterization of Liquid Hydrocarbons

6.3.2.1. Solvent Extraction and Liquid Chromatography

Only two samples have been analyzed from the Sydney Basin. These samples

are from a source rock (sample no. 35) sample in the Ingonish #1 well 39.9m

(131 ft) and one stained reservoir rock (sample no. 63) from the North Sydney F-

24 well at 1363.3m (4473 ft). The source rock from the Windsor Group (sample

35) has a high extract yield (>1000 ppm), whereas the reservoir rock from the

North Sydney G-24 or F-24 well (sample 63; Figure 2a) has moderate extract

yield (768 ppm).

Both samples have relatively higher polar compounds (NSO and asphaltene).

The relative proportions of saturate and aromatic hydrocarbons, NSO

compounds and asphaltenes showed that both have less than 50%

hydrocarbons of the total extract yield from these two sediments. The ternary


68

diagram of liquid chromatographic separation shows that samples 35 and 63 may

have similar composition although they do not have any genetic relationship.

6.3.2.2. Gas Chromatography of the Saturate Fraction

The gas chromatograms of both samples (35 and 63) indicate somewhat of a

depletion in normal alkanes and elevated chromatographic baselines ("hump"

due to the unresolved complex mixture of hydrocarbons) (Figures 27a and 27b).

This is an effect of possible biodegradation. However, sample 63 (reservoir rock

from North Sydney F-24) has been more biodegraded than sample 35 (Ingonish

well source rock). The low pristine/phytane (pr/ph) ratio (0.5; Table 5a [ii]) of the

sample from the North Sydney F-24 well suggests that it has been deposited in a

reducing environment. On the other hand, a slightly higher pr/ph ratio in sample

35 may suggest a dysoxic depositional environment. However, an advanced

biodegradation in sample 63 may have changed these ratios as

isoprenoid/normal alkane ratios tend to be elevated in the case of biodegraded

samples. Otherwise, the n-alkane distributions of both samples indicate that they

are genetically different. A major hump of low molecular weight hydrocarbons in

relation to the low maturity of sample 35 (Ingonish #1 well) indicates a marine

algal input. On the other hand, a higher concentration of high molecular weight

hydrocarbons in sample 63 indicates a terrestrial organic matter input.

6.3.2.3. Gas Chromatography – Mass Spectrometry: Saturate Biomarkers

Table 8b illustrates the semi-quantitative area percentages of various

compounds within triterpane (m/z 191) and sterane (m/z 217) groups. Figures

28a (i) and 28b (i) show the mass chromatograms of triterpanes for samples 35

(Ingonish #1, 39.9m or 131 ft.) and 63 (North Sydney F-24/G-24, 1363.3m or

4473 ft), respectively. Figures 28a (ii) and 28b (ii) show the mass chromatograms

of sterane distributions for samples 35 (Ingonish #1, 131ft [39.9m]) and 63 (North

Sydney F-24/G-24, 1363.3m, respectively. This data shows distinct differences in

the triterpane (m/z 191) and sterane (m/z 217) distribution pattern for two

analyzed samples.


69

Both the sterane and triterpane distribution of both samples illustrate some

distinct differences. Sample 35 is somewhat enriched in C29 sterane. Both

samples have relatively high diasterane content than the regular content. Sample

63 has a relatively equable distribution of steranes. However, the low signal to

noise ratio of its m/z 217 mass chromatogram is suggestive of high (late oil

window) maturity, which is close to the point of thermal destruction of steranes.

By considering the relative proportions of steranes, hopanes and tricyclic

terpanes, it is apparent that sample 63 (North Sydney F-24, 1363.3m [4473ft] is

significantly richer in tricyclics than the other sample. Sample 63 is relatively

depleted in steranes, most likely due to elevated thermal maturity as discussed

above.

An extract of sample 35 (Ingonish #1 well at 39.9m or 131ft) is relatively enriched

in the C27 18αH-trisnorhopane (Ts, peak L), C29 18αH-norneohopane (29Ts, peak

S), C30 17αH diahopane (peak T), as well as the C24 tetracycline terpane (peak

H). This feature was not seen in sample 63 extract from North Sydney well as

gammacerane is maturity-sensitive. Moreover, high hopane/sterane ratio in

sample 63 is indicative of a strong terrestrial influence. On the other hand, the

sample from the Ingonish #1 well (no. 35) has quite low hopane/sterane ratio

suggesting a strong influence of marine organic matter.

The maturity of these two samples could be evaluated from the Ts/Tm ratio,

percentages of C30 moretane and 22S/(22S + 22R) C31 hopanes. Accordingly,

the offshore oil-stain sample (no. 63) has a maturity between 0.7 and 1.0% Ro

equivalent. The liquid hydrocarbons of sample 35 have possibly been generated

at maturity below 0.6% Ro, supporting the measured data of these samples.

Based on the GC and GC-MS fingerprinting, it is implied that the stained

sandstone in N. Sydney F-24 (sample 63) might have been derived from mixture

(both terrestrial and marine) of source rocks. The main component is derived


70

from terrestrial Mabou Group shale. On the other hand, a sample from the

Ingonish #1 well is mainly derived from a marine Windsor Group carbonate

source. This data suggests that the bitumen in Ingonish #1 well has been

generated in-situ.

6.3.3. Reservoir Analysis: Porosity and Permeability The representative data on porosity, permeability, and grain density of ten

selected reservoir units from the Cumberland (South Bar Formation), Mabou

(Point Edward Formation), Windsor (Meadows Road and Macumber Formation),

and one doubtful Horton Group sandstones reveal that all three Mabou Group

sandstones have high porosity and permeability (Table 7c). One fractured

limestone from the Macumber Formation and the Horton Group (?) sandstone

from the Ingonish #1 well also show high porosity and permeability. However,

other limestones from the Windsor Group have also shown high porosity but the

permeabilities are less than 1 mD. The porosity and permeability data from the

North Sydney well showed higher values than the earlier data from the

Robertson Research Group. The current findings suggest there may be

prospective reservoirs in the Mabou and Windsor Groups in the offshore portion

of the Sydney Basin.

7. RISK ASSESSMENT AND DEFINING THE PETROLEUM

POTENTIAL: CONCLUSIONS The current report attempts to enhance the overall understanding of the oil and

gas potential in relation to the petroleum systems of three major areas (Western

Cape Breton, Central Cape Breton, and Sydney subbasins) of Cape Breton

Island. The current study does not include any analysis for visualizing

hydrocarbon migration and entrapment within various play types using Petroleum

System Modelling. Therefore, the assessment of the Petroleum Potential of Cape

Breton Island has been performed based on limited seismic, geological, and

selected geochemical fingerprinting. Accordingly, the author (Dr. P. K.

Mukhopadhyay) feels that the current report should be treated as a preliminary


71

landmark towards detailed petroleum systems study on individual subbasins

(Phase II Study) from Cape Breton Island in the future. On the geological

standpoint of view, new 2D seismic interpretative data is required within these

specific subbasins.

Based on the current geological and geochemical interpretations, the following

conclusions on Petroleum Potential of Cape Breton Island could be established:

7.1. WESTERN CAPE BRETON SUBBASINS 7.1.1. Geological Interpretations The limited seismic data and structural cross-section of Mabou-Ainslie subbasin

indicate the following (Chapter 3.6.3):

Both Play Type #1 and Play Type Type #2 of the Horton Group may be

present in this region. Play type #1 represents the sandstone reservoirs

within the Strathlorne and Ainslie formations that occur within anticlinal

structures forming a combination of stratigraphic and structural traps,

whereas Play Type #2 represents the sandstone reservoirs within the

Strathlorne and Ainslie formations that lie beneath gently-dipping reverse

faults,

Some specific play types #1 (carbonate bioherm reservoirs; Figure 10)

and #2 (up-dip truncation of carbonate reservoirs against evaporate)

within the Windsor Group could be expected especially within the deeper

part of the Mabou-Ainslie subbasin or depocentre.

7.1.2. Geochemical Interpretations The geochemical fingerprinting (from a limited analytical database) of sediments

from the Mabou-Ainslie subbasin suggests that: Lower Carboniferous sediments of the Horton Group from the northern

part of this subbasin have potential organic-rich oil-prone source rocks,

which still lie within the “Oil Window”. On the other hand, similar sediments

from the southern part those have been associated with major folding and


72

thrusting, have only minor gas-prone source rocks; these sediments

mostly lie within the late phase of the condensate generation.

The upper Carboniferous Mabou and Cumberland Group sediments are

prolific gas- and condensate-prone source rocks

All oil stained reservoirs indicate that they are derived from the lacustrine

source rocks of the Horton Group (possibly from Strathlorne Formation).

Marine carbonate source rocks from the Windsor Group (especially the

Macumber Formation) did not contribute much for the oil seeps and stains

from Lake Ainslie and surrounding areas (this report; Fowler et al., 1994).

7.1.3. Petroleum System Components and Oil/Gas Potential Most of the petroleum prospects in the Lower Carboniferous play types of

the Mabou-Ainslie subbasin are restricted to the Horton Group. There are

large stratigraphic gaps within the Windsor Group in this area due to an

effect of a major, extensional, bedding-parallel, detachment fault.

Both the play types # 1 and #2 of the Horton Group may represent the

highly oil stained sandstone reservoirs surrounding the Lake Ainslie

region. Most of these oil seeps and stains in that region are present within

uplifted and structurally disturbed shallow reservoirs, which are highly

porous (>10%) and permeable (>5 mD) and are biodegraded.

Previous studies on one dimensional petroleum system modeling of Lower

Carboniferous sediments from other basins of onshore Nova Scotia

indicate that expulsion of crude oil from source rocks of the Horton Group

occurs within 320-315 Ma (after the deposition and of the Windsor Group

sediments) and around 300-280 Ma for the Windsor Group.

Considering the overall thermal maturity and the timing of the reservoir

compaction of the Horton Group sediments in relation to the timing of

crude oil expulsion from the Lower and Middle Horton Group source rocks,

it is projected that highly porous and permeable reservoirs of play types #1

and #2, which are situated within a depth of 500-1500 m could be charged

with crude oil. Accordingly, the sealing efficiency of Upper Horton Group


73

shale or Windsor Group carbonates on top of these crude oil reservoirs

may improve. Accordingly, the deeper part (500-1500 m) of the Ainslie

depocentre (especially in the northern part), is considered to be a potential

area for a future liquid (oil and condensate) hydrocarbon discovery. These

play types (#1 and #2) could be similar to the past-productive

Carboniferous Stoney Creek Field in New Brunswick that has produced

800 thousand barrels of oil and 30 BCF of natural gas between 1906 and

the 1991.

The lack of oil stains or gas shows in any of the previously drilled wells,

the presence of highly disturbed structures, the absence of potential

source rocks, and elevated thermal maturity within the southern part of the

Mabou-Ainslie subbasin (Mull River #1 well and further south) may

indicate a low oil and gas potential for the lower Carboniferous sediments.

The channel sandstones from the upper Carboniferous Cumberland

Group (Boss Point Formation) that occur in similar structural settings of

the Horton Group play types #1 and #2 may have a major potential for gas

and condensate condensate discovery in the southern part of the Lake

Mabou-Ainslie subbasin. However, current seismic data does not show

any promising 3- or 4-way closures. Limited seismic data prevents the

current study to predict any presence of other potential play types within

the Horton and Windsor Groups of sediments.

7.2. CENTRAL CAPE BRETON SUBBASINS 7.2.1. Geological Interpretations As discussed earlier, the following structural and play type interpretation of only

the Bras d’Or subbasin could be evaluated due to lack of any seismic and other

relevant geological data (especially from the Loch Lomond subbasin):

The Bras d’Or subbasin is an oval-shaped, northeast-trending

synclinorium that has been affected by syn- and post-Carboniferous

folding and faulting. In this area, Windsor Group strata are in direct contact

with the overlying basement rocks with an angular unconformity. Horton


74

Group strata have not been penetrated in any of the wells. Since there is

no seismic data available in this region for this study, they are postulated

to be present only in basin-centre locations.

Within the Macumber Formation of the Lower Windsor Group and other

carbonates of the Middle Windsor Group, previously unidentified

biohermal lithofacies forming Play Type #1 may be identified (see chapter

3.6.2.3). The reservoirs in Play Type #1 may have developed along basin

margins and on subtidal paleo-topographic highs. Some of the oil-stained

reservoirs Malagawatch and Jubilee wells may have close affinities with

Play Type #1 within the Windsor Group. However, the low porosity and

permeability data of the selected analyzed reservoirs indicates the

requirement of systematic study on the physical analysis of the more

reservoir rocks using the interpretation of new 2D seismic data.

7.2.2. Geochemical Interpretations The source rock potential and biomarker interpretation of the oil-stained

reservoirs or crude oil has established that:

Most of the Windsor sediments (especially the Macumber Formation) are

organic-rich and have crude oil potential and lie within the “Oil Window”.

The deeper mature sediments from this group have gas and condensate

potential.

Selected stains and oil samples (one crude oil and six oil-stain source or

reservoirs) from the Windsor Group are genetically related to two distinct

source rock types:

(1) crude oil from the Malagawatch M-9 well and one stained

carbonate reservoir from ATG-17-77 (Jubilee area) was derived from a

marine carbonate source rock (possibly from the Macumber

Formation); the crude oil shows a maturity of 0.8-1.0% Ro, whereas

the other oil stain from the ATG well is derived from 0.5 to 0.7% Ro

(2) five oil stains are derived from a mixture of hypersaline marine


75

carbonate (Windsor Group) and lacustrine (Horton Group) or terrestrial

(Horton or Windsor Groups). The reservoir and source rocks from four

of these sediments are derived from a maturity of 0.7 to 0.9% Ro and

the oil-stained source rock from the McIver Pt #1 well has a low

maturity (<0.6% Ro). Both the McIver Pt #1 oil stains are partially

biodegraded.

7.2.3. Petroleum System Components and Oil/Gas Potential Most of the petroleum prospects are concentrated within fractured

carbonate reservoirs of play type #1 of the Windsor Group. Although the

porosity data from the selected bioherm reservoir rocks appears

promising, the permeability data of this study indicates that potential oil-

stained fractured reef (bioherm) carbonate reservoirs have not yet been

studied,

The play type #2 (up-dip truncation of carbonate reservoirs against salt

diapirism or fault) and associated sub-salt plays could be significant

especially within the Malagawatch-Bras d’Or area. The low maturity of the

sub-salt play could be of importance within the deeper part of the Bras-

d’Or subbasin in discovering medium gravity crude oil including the Jubilee

areas.

The implication of the following petroleum system parameters suggests a

major prospect of crude oil within the Middle to lower Windsor Group

(700m) play type #1 and #2 reservoirs:

o Abundance of oil and oil-stains within the Windsor Group

carbonates within the Bras-d’Or subbasin (including the Jubilee

area),

o Presence of mature oil-prone source rocks,

o The timing of liquid hydrocarbon expulsion (300 to 280 Ma) from

the Windsor Group is later than the timing of compaction of the

Windsor Group reservoirs (~335 to 325Ma; earlier 1-D modelling),


76

o Possible presence of the bioherm and ramp facies reservoirs within

the sub-salt plays could be extremely important below 1000 m.

7.3. SYDNEY BASIN 7.3.1. Geological Interpretations The Sydney Basin has a prominent northeast structural trend that has been

modified by the superposition of an east-trending element in the Pennsylvanian

strata of the Morien Group. The Pennsylvanian (Upper Carboniferous) strata

within the basin area are folded into broad, open asymmetric synclines and

anticlines with an arcuate fold axis. These folds appear to be related to the

faulted and folded Mississippian rocks situated on the basement fault blocks. The

structural and play type interpretation of Sydney Basin could not be evaluated

due to lack of seismic and other data.

7.3.2. Geochemical Interpretations The source rock potential and biomarker interpretation of the oil-stained

reservoirs or source rocks has indicated the following:

In the southern and western parts of the Sydney Basin, most of the

Windsor Group and Cumberland Group sediments lie within the “Oil

Window”. The Windsor Group sediments are organic-rich and have high

potential for crude oil. With the exception of oil shale samples from the

Cumberland Group, most of the sediments from this Group has gas and

condensate potential.

The biomarker analysis of two oil stain carbonates from the Windsor

Group are genetically related to two distinct source rock types

Mukhopadhyay, 2000):

(1) a marine carbonate source and is derived from a maturity of 0.5 to

0.7% Ro; and

(2) a mixture of hypersaline marine carbonate (Windsor Group) and

terrestrial (possibly from the Mabou Group) source rock with a maturity

of 0.7 to 0.9% Ro.


77

7.3.3. Petroleum System Components and Oil/Gas Potential Most of the petroleum prospects within the onshore Sydney Basin are

mainly restricted to bioherm play of the Windsor Group and channel

sandstone reservoirs of the Cumberland Group, which have a combination

of structural and stratigraphic traps. The Horton Group sandstone play

type #1 could be of importance possibly within the offshore Sydney

subbasin.

Based mainly on the source rock potential, oil potential of the Sydney

Basin is restricted in the Windsor Group to the western (east of Boisdale

Inlier, Figure 3b) and in the southern part (Glen Morrison, etc.). However,

the liquid hydrocarbons in those parts of the subbasin are expected to be

of higher gravity compared to the Bras d’Or subbasin. The major gas

potential of the Cumberland Group is restricted to the northern part of the

onshore areas and in offshore Sydney Basin.

8. ACKNOWLEDGMENTS The author has expressed sincere thanks and acknowledgement to Paul Harvey,

Paul Wamback, and Sandy MacMullin of Nova Scotia Department of Energy

Halifax, Nova Scotia, Canada and Cape Breton Development Corporation for the

contract. The author has acknowledged the permission of Total Inc., Calgary,

Alberta for the use of various data and figures from the author’s Sydney Basin

Geochemical Report and has expressed sincere thanks for their help. The author

acknowledges W. G. Shaw from the W. G. Shaw and Associates for his

contributions on parts of the geology and structure. The author sincerely

acknowledges the help of the scientists from various organizations for their

fruitful discussions on geology, structural set up, and sample collection: Peter

Giles from the Geological Survey of Canada; Bob Boehner, John Calder, Robert

Naylor, and Bob Ryan from the Nova Scotia Department of Natural Resources;

Paul Durling from Corridor Resources; and Kim Doane, Paul Harvey, Kris

Kendall, and Jack MacDonald from the Nova Scotia Department of Energy. The


78

author conveys special thanks to Bob Boehner, Paul Durling, Peter Giles, and

Paul Harvey for their various support. The author acknowledges the help of Paul

Durling from Corridor Resources for reviewing parts of the early version of the

report. The author also expresses his sincere thanks to John MacMillan from the

Core Library of the Nova Scotia Department of Natural Resources, Stellarton,

Nova Scotia for his enormous help during the collection of samples. The author

acknowledges the help of Jack MacDonald and Paul Harvey for the review of the

draft manuscript of this report.


79

9. REFERENCES CITED Allen, T. L. 1998. Sedimentology, sequence stratigraphy, and source rock potential of the Upper Carboniferous Colindale Member, Port Hood Formation, Western Cape Breton Island. Master of Science Thesis. Dalhousie University, Halifax, Nova Scotia, 195p. Boehner, R. C. and Giles, P. S. 1993. Geology of the Sydney Basin, Cape Breton and Victoria Counties, Cape Breton Island, Nova Scotia. Nova Scotia Department of Natural Resources, Mines and Energy Branch, Memoir 10? Boehner, R. C. and Prime, G. 1993. Geology of the Loch Lomond Basin and Glengarry Half-Graben, Nova Scotia, Nova Scotia Department of Energy, Mines and Minerals Branch, Memoir 9, 68p. Boehner, R. C., Giles, P. S., Murray, D. A. and Ryan, R. J. 1989: Carbonate buildups of the Gays River Formation, Lower Carboniferous Windsor Group, Nova Scotia; in Reefs of Canada and Adjacent Areas, eds. H. H. J. Geldsetzer, N. P. James and G. E. Tebutt; Canadian Society of Petroleum Geologists, Memoir 13, p. 609-621. Boehner, R. C. and Giles, P. S. 1986. Geological map of the Sydney Basin, Nova Scotia. Nova Scotia Department of Mines and Energy, Open File Map 86-1, scale 1: 50,000 Boehner, R. C. 1986. Salt and Potash Resources in Nova Scotia. Nova Scotia Department of Mines and Energy, Bulletin 5, 346p. Boehner, R. C. 1985. Carboniferous basin studies, salt, potash, celestite and barite-New exploration potential in the Sydney Basin, Cape Breton Island; in Mines and Minerals Branch, Report of Activities 1984; Nova Scotia Department of Mines and Energy, Report 85-1, p. 153-164. Burwood, R.P., Leplat, P., Mycke, B., and Paulet, J. (1992) Rifted margin source deposition: a carbon isotope and biomarker study of west African Lower Cretaceous “lacustrine” section: Organic Geochemistry, V. 19, p. 41-52. Fowler, M.G., Hamblin, A.P., MacDonald, D.J. and McMahon, P.G. 1993. Geological occurrence and geochemistry of some oil shows in Nova Scotia. Bull. Can. Petrol. Geol. v. 41, no. 4, p. 422-436. Cooper, B. S., Bernard, Fisher, M. J. and Buttersworth, J. S. 1976. Report on a petroleum geochemical evaluation of the Shell et al., North Sydney G-24 well, Sydney Basin, Offshore Nova Scotia, East Canada, Robertson Research International Limited, North Wales Report Number 4007P, 7 pages and 15 figures


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Cooper, B. S., Bernard, P. C., Coleman, S. H. Darlington, C. and Buttersworth, J. S. 1974. Report on a maturation and source rock evaluation study of the Murphy et al. North Sydney P-05 well, Offshore Nova Scotia. Robertson Research International Limited Report Number 2780, 5 pages and 10 figures/tables. Durling, P., Harvey, P., and Howells, K. 1995a. Geophysical evidence for thrust faulting in the Carboniferous Antigonish-Mabou Subbasin, Nova Scotia. Atlantic Geology, v. 31., p. 183-196. Durling, P., Howells, K., and Harvey, P. 1995b. The near surface geology of St. Georges Bay, Nova Scotia. Can. Jour. Earth Sc., v.32.,p.603-613. Espitalie, J., Deroo, Cr., and Marquis, F. 1985. Rock-Eval pyrolysis and its applications. Rep. Inst. Fr. Petrol. 33878, 72p. Felderhof, H. 1975. Petroleum Reservoir Study. Nova Scotia Department of Mines and Energy Open File Report 649. Gibling, M. R., Boehner, R.C. and Rust, B. R. 1987. The Sydney Basin of Atlantic Canada, an Upper Palaeozoic Strike-Slip basin in a collisional setting. In Sedimentary Basins and Basin-Forming Mechanisms (Eds. C. Beaumont and A. J. Tankard), Can. Soc. Petrol. Geol. Memoir 12, p. 269-285. Giles, P. S. and Boehner, R.C. 2001. Geological Mapping for Mineral Development: South-central Cape Breton Island, Targeted Geoscience Initiative (TGI). Windsor Group Field Trip Guidebook, May 22-23, 2001, 35p. Giles, P.S., and Boehner, R.C. in prep. 2001:Windsor Group stratigraphy and structure drill core orientation field trip 2001 guidebook; Nova Scotia Department of Natural Resources, Minerals and Energy Branch, Open File Report ME 2001-??, ??p. Giles, P.S. 2001. Geology of the McIntyre Lake Salt Deposit; in D. R. MacDonald ed. Mining Matters for Nova Scotia, Opportunities for Economic Development, Nova Scotia Department of Natural Resources, Minerals and Energy Branch, Report ME 2001-2, p. 9. Giles, P.S. 2001. Stratigraphy and structure of the Malagawatch Salt Deposit; in D. R. MacDonald ed. Mining Matters for Nova Scotia, Opportunities for Economic Development, Nova Scotia Department of Natural Resources, Minerals and Energy Branch, Report ME 2001-2, p. 10. Giles, P.S., Hein, F.J. and Allen, T.L. 1997. Bedrock Geology of Port Hood- Lake Ainslie (11K/04, 11K/03, 11F/13), Cape Breton Island, Nova Scotia; Geological Survey of Canada, Open File Map 3253, Scale 1:50000


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Giles, P.S. 1981: Major Transgressive and regressive cycles in the middle to late Viséan rocks of Nova Scotia; Nova Scotia Dept. of Natural Resources Paper 81-2; 27p. Giles, P. S. and Lynch, G. 1993: Bedding-parallel faults, breccia zones, large-scale recumbent folds and basin evolution: the case for extensional tectonics in the onshore Magdalen Basin in Nova Scotia; Abstract in Program and Abstracts, Atlantic Geoscience Society Annual Colloquium and Symposia, Halifax, p. 7. Grist, A. M. and Gibling, M. R. 1999. Apatite Fission Track Modelling of 3 samples from the North Sydney F-24 and P-05 wells. In Geology and Hydrogeology of the Subsea Mining District, Sydney Coalfield, Nova Scotia (Eds. M. R. Gibling, A. T. Martel, and M. H. Nguyen. Unpublished Report, centre for Marine Geology, Dalhousie University, Halifax, Nova Scotia, 8-1 to 8-33. Grist, A., Ryan, R., and Zentilli, M. 1995: The Thermal Evolution and Timing of Hydrocarbon Generation in the Maritimes Basin of Eastern Canada; Bulletin of Canadian Petroleum Geology, v. 43, pp. 145-155. Hacquebard, P. A. 2002. Potential coalbed methane resources in Atlantic Canada. Int. Jour. Coal Geol., v. 52, p. 3-28. Hacquebard, P.A.1986:The Gulf of St. Lawrence Carboniferous Basin; The Largest Coalfield of Eastern Canada; CIM Bulletin, v.79, (981): 67-78 Hacquebard, P. A. 1984. Coal rank changes in the Sydney and Pictou coalfields; cause and economic significance. Canadian Institute of Mining Bulletin, v. 77, p. 33-40. Hacquebard, P. A. 1976. Appraisal of coal intersected in Murphy offshore well (North Sydney P-05) of Sydney Coalfield, Nova Scotia. Geological Survey of Canada, Technical Report No. 11-K/G-76-3. Hacquebard, P. A. and Donaldson, J. R. 1969. Carboniferous coal deposition associated with flood plain and limnic environments in Nova Scotia. In: Dapples, E.C., Hopkins, M.E. (Eds.), Environments of Coal Deposition. Geological Society of America, Special Paper 114, pp. 141-191. Hamblin, A. P. 1989. Sedimentology, tectonic control and resource potential of the Upper Devonian – Lower Carboniferous Horton Group. Cape Breton island, Nova Scotia, Ph.D. Thesis, University of Ottawa, 300p. Hamblin, A.P. and Rust, B.R. 1989. Tectono-sedimentary analysis of alternate-polarity half-graben basin-fill successions: Lake Devonian – Early Carboniferous Horton Group, Cape Breton Island, Nova Scotia; Basin Research, v. 2, pp. 239-255.


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Hunt, J.M. 1995. Petroleum Geochemistry and Geology. W. H. Freeman and Company, New York, 743p. Kendall, S. and Altebaumer, F. 1984. Geochemical Evaluation of Petro-Canada St. Paul P-91, 600-2883m (T.D.), Final Proprietary Report Number G/S-118. Lynch, G. and Brisson, H. 1994. Ainslie Detachment in the Carboniferous River Danys Basin of Cape Breton Island, Nova Scotia, with regional implications for Pb-Zn mineralization. In Current Research 1994-D, Geological Survey of Canada, p. 57-62. Lynch, G and Brisson, H. 1995. Bedrock Geology, Whycocomagh (11-F-14), Geological Survey of Canda, Open File #2917, Scale 1:50,000, with marginal notes Magoon, L. B. and Dow, W. G. 1994. The petroleum system. . In The Petroleum System – from Source to Trap (Edited by L. B. Magoon and W. G. Dow). American Association of Petroleum Geologists Memoir 60, p. 1-24. Martel, T.A and Gibling, M. 1996: Stratigraphy and Tectonic History of the Upper Devonian to Lower Carboniferous Horton Bluff Formation, Nova Scotia; Atlantic Geology, v32, pp. 13 - 38. Martel, A.T., Gibling, M. R. and Nguyen, M. 2001. Brines in the Carboniferous Sydney Coalfield, Atlantic Canada. Applied Geochemistry, v. 16, p. 35-55. McMohan, P., MacDonald, D. J. and Boehner, R. C. 1989. Petroleum onshore Nova Scotia. Draft Note submitted to Geological Society of America for the Publication “Geology of the Late Paleozoic – Early Mesozoic Basins in Nova Scotia: Energy Resources; Contribution to the Decade of North American Geology”, North Appalachian Volume. 5p. McMahon, P., Short, G., and Walker, D. 1986. Petroleum wells and drillholes with petroleum significance, Onshore Nova Scotia. Nova Scotia Department of Mines and Energy Information Series 10, 194p. Moldowan, J.M., Seifert, W.K., and Gallegos, E.J. 1985. Relationship between petroleum composition and depositional environment of petroleum source rocks. AAPG Bulletin, Vol. 69, p. 1255-1268. Moldowan, J.M., Fago, F.J., Carlson, R.M.K., Young, D.C., Van Duyne, G., Clardy, J., Schoell, M., Pillinger, C.T., Watt, D.S. 1991. Rearranged hopanes in sediments and petroleum. Geochim. Cosmochim. Acta, 55, p.3333-3353.


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Mossman, D. J. 1992. Carboniferous source rocks of the Canadian Atlantic Margin. In: Basins of the Atlantic Seaboard: Petroleum Geology, Sedimentology and Basin Evolution (Ed. J. Parnell), Geological Society London Special Publication No. 62, p. 25-34. Mukhopadhyay, P. K. 2000. Evaluation of petroleum potential of Devonian-Carboniferous rocks from the Sydney Basin and surrounding subbasins from the Eastern/Central Cape Breton Island, Nova Scotia. Unpublished and Confidential Final Contract Report submitted to Total Fina Inc., Calgary, Alberta. 38p. with tables figures, and appendices Mukhopadhyay, P. K., MacDonald, D.J., Harvey, P.J., Boehner, R.C., Calder, J.H. and R. Ryan. 2000. Petroleum System of the Carboniferous rocks from onshore Nova Scotia. International Journal of Coal Geology, v. 43 (1-4), p. 137-139 Mukhopadhyay, P.K., Goodarzi, F., Crandlemire, A. L., Gillis, K. S., Macneil, D. J. and Smith, W. D. 1998. Comparison of coal composition and elemental distribution in selected seams of the Sydney and Stellarton Basins, Eastern Canada. Int. Jour. Coal Geol., v. 37, p.113-141. Mukhopadhyay, P.K., MacDonald, D.J, Calder, J. H., Hughes, J. D., and Hatcher, P.G., 1997. Relationship between Methane Generation/Adsorption Potential, Micropore System, and Permeability with Composition and Maturation – Examples from Carboniferous Coals of Nova Scotia, Eastern Canada. Proc. International Coalbed Methane Symposium, Tuscaloosa, Alabama, Paper 9733, p. 183-193. Mukhopadhyay, P. K., Hatcher, P.G., Calder, J. H. 1991. Hydrocarbon generation from deltaic and intermontane fluviodeltaic coal and coaly shale from the Tertiary of Texas and Carboniferous of Nova Scotia. In Coal and Terrestrial Organic Matter as a Source Rock for Petroleum (Mukhopadhyay, P. K. et al. editors), Org.Geochem. v. 17, No. 6., p. 765-784. Pergamon Press. Oxford. Mukhopadhyay, P. K. 1991. Source rock potential and maturation of Paleozoic sediments (Devonian-Carboniferous) from onshore Nova Scotia. 186 pages, 11 maps, Open File Report of the Department of Natural Resources 91-012. Pascucci, V., Gibling, M. R. and Williamson, M. A. 2000. Late Paeozoic to Cenozoic history of the offshore Sydney Basin, Atlantic Canada. Can. Jour. Earth. Sc., v. 37., p. 1143-1165. Peters, K.E., Moldowan, J.M. 1993. The Biomarker Guide. Prentice-Hall, Englewood Cliffs (363 pp.).


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Peters, K. 1986. Guidelines for evaluating petroleum source rock using programmed pyrolysis. Bull. Amer. Assoc. Pet. Geol. V. 70, p. 318-329. Roliff, W.A. 1955. Eastern Canada’s Six Potential Oil Provinces: Oil and Gas Journal, Vol. 54, No. 15, pp.114 – 119. Roliff, W.A. (Imperial Oil Ltd.) 1960. Report on Exploration Work Carried Out Between July 1st of 1959 and Jun 30th of 1960; for Imperial Oil; NSDNR Assessment Report No.11-K-03 39-J-00 (07); Ryan, R.J., Boehner, R.C., and Calder, J.H. 1991: Lithostratigraphic revision of the Upper Carboniferous to Lower Permian strata in the Cumberland Basin, Nova Scotia and the regional implications for the Maritimes Basin in Atlantic Canada; Bulletin of Canadian Petroleum Geology, v.39, no.4, pp. 289-314. Rehill, T. A. 1996. Late Carboniferous nonmarine sequence stratigraphy and petroleum geology of the Central Maritimes Basin. Ph.D. Thesis, Dalhousie University, Halifax, Nova Scotia. Ryan, R.J., Grist, A. M. and Zentilli, M. 1990. The thermal evolution of the Maritimes Basin: Evidence from Apatite Fission Track Analysis. Nova Scotia Department of Mines and Energy, Mineral Development Division Report of Activities 91-1, p. 27-32. Schenk, P. E. 1967: The Macumber Formation of the Maritime Provinces, Canada, a Mississippian analogue to recent strandline carbonates of the Persian Gulf; Journal of Sedimentary Petrology, v. 37, no. 2, p. 365-376. Schenk, P. E. 1967: The significance of algal stromatolites to paleo-environmental and chronostratigraphic interpretations of the Windsorian Stage (Mississippian), Maritime Provinces; in Collected Papers on the Geology of the Atlantic Region; Geological Association of Canada, Special Paper No. 4, p. 229-243. Schenk, P. E. 1969: Carbonate-sulphate-redbed facies and cyclic sedimentation of the Windsorian Stage (Middle Carboniferous), Maritime Provinces; Canadian Journal of Earth Sciences, v. 6, no. 5, p. 1037-1066. Schenk, P. E. 1984: Carbonate-sulfate relations in the Windsor Group, central Nova Scotia, Canada; in Ninth International Congress on Carboniferous Stratigraphy and Geology, Compte Rendu, v. 3, p. 143-162. Shawnee Petroleums Ltd. 1973. A comprehensive regional report submitted as a partial requirement of the work commitments on the Petroleum and Natural gas Licenses 335, 336, 337, 338, 339, and 375 for the Province of Nova Scotia. November 26, 1973.


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Short, G. 1986. Surface Petroleum Shows: Onshore Nova Scotia, Nova Scotia Department of Mines and Energy Information Series No. 11, 29p. St. Peter, C. 1992. Lithological Facies, Seismic Facies and Strike-Slip Setting of the lower Carboniferous Alluvial/Fluvial/Lacustrine Albert Formation of New Brunswick; New Brunswick Dept. of Natural Resources, Geoscience Report 92-02, 140 p. St. Peter, C. 1994: Maritimes Basin evolution; key geologic and seismic evidence from the Moncton Subbasin of New Brunswick. Atlantic Geology, v.29, pp. 233-270. Stach, E., Mackowsky, M. Th., Teichmuller, M., Taylor, G. H., Chandra, D., and Teichmuller, R. (1982) Textbook of Coal Petrology. 3rd Ed. 536 p. Borntraeger, Stuttgart. Tissot, B. and Welte, D. H. (1984). Petroleum Formation and Occurrence. Springer-Verlag, Berlin, 699 p. Utting, J. 1987. Palynology of the Lower Carbonifeous Windsor Group and Windsor-Canso Boundary Beds of Nova Scotia; Geological Survey of Canada, Bulletin 374; 93 p. Utting, J. and Hamblin, A.P. 1991. Thermal Maturity of the Lower Carboniferous Horton Group, Nova Scotia; International Journal of Coal Geology; v. 19, pp. 439-456. Zumberge, J.E. 1987. Prediction of source rock characteristics based on terpane biomarkers in crude oils. A multivariate approach: Geochemica Cosmochemica Acta, v. 51, p. 1625-1637.


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LIST OF TABLES Table 1. Petroleum Exploration Wells a. Ainslie Depocentre and Antigonish-Mabou Subbasin b. Bras d’Or Subbasin and Sydney Basin Table 2. List of Collected Samples (cores, cuttings, and outcrops) with depth, well name, stratigraphic units, lithological entities and analytical protocol. Table 3. Rock-Eval and Total Organic Carbon (TOC) data derived from current contract (western and central Cape Breton Subbasins + Sydney Basin from Mukhopadhyay, 2000: permission from Total Inc., 2004) a. Rock-Eval and TOC data from Western Cape Breton Subbasins b. Rock-Eval and TOC data from Central Cape Breton Subbasins (part of

the data from current contract and part of the data is from Mukhopadhyay, 2000: permission from Total Inc., 2004) c. Rock-Eval and TOC data from the Sydney Basin (permission from Total Inc., 2004)

Table 4. Vitrinite Reflectance data from Western and Central Subbasins and Sydney Basin (current Data and Data [partly from Central and all of Sydney Basin] from Mukhopadhyay, 2000: Permission from Total Inc., 2004) Table 5. Wet chemistry and gas chromatographic data from the oil stains analysis of current contract Western and Central Cape Breton Subbasin and from Sydney Basin (Mukhopadhyay, 2000: permission from Total Inc., 2004): a. Wet chemistry (bitumen extract and liquid chromatographic separation) (i) Western and Central Cape Breton Subbasins (data from current contract (ii) Central Cape Breton Subbasins and Sydney Basin (data from Mukhopadhyay, 2000; permission from Total Inc., 2004) b. Gas chromatography data (current contract) Table 6. Gas chromatography mass spectrometry data a. Oil stains from Western and Central Cape Breton Subbasins (current contract data) b. Three oil stains and one crude oil sample from Central Cape Breton Subbasin and Sydney Basin (data from Total Fina Contract – Mukhopadhyay, 2000: permission from Total Inc., 2004) Table 7. Reservoir Analysis data a. From Western Cape Breton Subbasins (data from current contract) b. From Central Cape Breton Subbasins (part of the data from current contract and part of the data is from Mukhopadhyay, 2000: permission from Total Inc., 2004)


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c. From the Sydney Basin (all data from Mukhopadhyay: permission from Total Inc., 2004).

LIST OF FIGURES Figure 1. Location of the Maritimes Basin Figure 2. Atlantic Geology Map a. Distribution of Carboniferous to Permian sediments within Maritimes Basin in Eastern Canada b. Location of the Study Area within the Carboniferous-Permian Basins of Nova Scotia Figure 3. Regional Geology map (11”x17” fold out) a. Southern Maritimes Basin b. Cape Breton Island Figure 4. Planimetric Map of Cape Breton Island with Historical Seismic Survey Lines (1:250,000) and well locations (in binder pocket of the final report) Figure 5. Generalized Geological map of Cape Breton Island (1:250,000) (in binder pocket of the final report) Figure 6. Litho- and Chronostratigraphy of the target Subbasins

a. Stratigraphic nomenclature for Late Devonian to Permian sediments of various subbasins from Cape Breton Island. b. A composite Lithostratigraphy of the Windsor Group from Central Cape Breton Subbasins (after Peter Giles, personal communication: from Mukhopadhyay, 2000: permission from Total Inc., 2004)

Figure 7. Seismic Line Chervon 62Y (in binder pocket of the final report) a. Uninterpreted b. Interpreted Figure 8. Structural Cross-Section – Mabou-Lake Ainslie depocentre (In binder pocket of the final report) Figure 9. Structiral Cross-Section – Bras d’Or Subbasin (In binder pocket of the final report) Figure 10. Conceptual Diagram of Petroleum Play Types of Cape Breton Island


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LIST OF FIGURES (continued) Figure 11. Petroleum Seeps and Oil-Stains a. Location Map of petroleum seeps and oil-stains within various subbasins of Cape Breton Island b. Windsor Group Carbonate Reservoir with crude oil, Well: ATG-8-76 (Jubilee area) Figure 12. Various Source Rocks – Outcrop and Core photos a (i) Horton Group organic-rich shale and sandstone: Type Section – Horton Bluff – Windsor Subbasin a(ii): Horton Group shale and sandstone (Strathlorne Formation: Location #13); Western Cape Breton Subbasins b(i): Dark limestone from Macumber Formation (Lowermost Windsor Group), Location #18, Western Cape Breton Subbasins b(ii): Dark limestone, Windsor Group, Well: LL-04, Loch Lomond area

c: Dark organic-rich shale and sandstone from the Mabou Group, Cape Dauphin outcrop section, Sydney Subbasin d. A example of a sequence of coal, carbonaceous shale, and sandstone from the Cumberland Group, Joggins Section, Cumberland Basin

Figure 13. Various Reservoir, Seal Rocks, Petroleum System Unit – Outcrop and Core photos a. Porous and permeable sandstone from the Horton Group; Location #3; Lake Ainslie Depocentre b. Fossiliferous limestone (bioherm facies) reservoir, Windsor Group, Cape Dauphin Outcrop Section c. A typical example of a porous reservoir sandstone from the Boss Point Formation, Cumberland Group d. A typical example of the seal rock (salt and anhydrite) from the Middle Windsor Group e. A typical oil-stained limestone and anhydrite reservoir rock from the Windsor Group, Bras d’Or subbasin (Jubilee area: well – ATG- 49-77) f. An example of Petroleum System parameters within a single core section from the Windsor Group, Well: ATG-49-77, Bras- d’Or Subbasin (1: source rock; 2: carrier bed; 3: reservoir rock; and 4: seal rock) Figure 14. Geological map of various subbasins within Cape Breton Island with well locations for samples (for details see Figure 5 in the pocket of the Report Binder). a. Western Cape Breton Subbasin b. Central Cape Breton Subbasins c. Sydney Basin (from Mukhopadhyay, 2000; permission from Total Inc., 2004)


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LIST OF FIGURES (continued) Figure 15. Cross-plots of various parameters from Rock-Eval pyrolysis and TOC data of samples from Western Cape Breon Subbasins:

a. Remaining hydrocarbon potential vs. TOC showing the location of samples for the Mabou-Ainslie Subbasin; The oil-prone source rock is from Horton Group of Lake Ainslie 88-1 well

b. Kerogen Type (pseudo van Krevelen-Type) diagram showing the potential of sediments from various of the Mabou-Ainslie Subbasin c. Kerogen Type determination of various samples from Mabou- Ainslie Subbasin based on Tmax vs. hydrogen index d. A plot of Tmax versus production index showing the position and HC Conversion of various samples from Mabou-Ainslie Subbasin

Figure 16. Maturity versus depth plot of various wells from the Mabou-Ainslie Subbasin Figure 17. Liquid chromatography data of four samples from Western and Central Cape Breton Subbasins Figure 18: Gas chromatogram of the saturate fraction of the oil-stain from the reservoir sandstone of the Horton Group; Well: Ainslie-88-1, Mabou-Ainslie Subbasin Figure 19. Various plots from triterpanes (m/z 191) and steranes (m/z 217) (saturate biomarker analysis from GC-MS) a. Terpane and sterane mass fragmentograms for oil-stained sandstone, Ainslie-88-1, Mabou-Ainslie Subbasin b. Plot of two maturity-sensitive saturate biomarker parameters with

position of four oil-stain samples from the Mabou-Ainslie Subbasin and Central Cape Breton Subbasin

c. A plot of two environmental sensitive saturate biomarker parameters (one is C29/C27 sterane) and position of four oil- stain samples from the Mabou-Ainslie and Central Cape Breton Subbasins

d. A plot of two environmental sensitive saturate biomarker parameters (C25/C26 tricyclics) and position of four oil-stain samples from the Mabou-Ainslie and Central Cape Breton Subbasins

e. A plot of two saturate biomarker parameter ratios (one is C29/C27 sterane and the other is gammacerane ratio) and position of four oil-stain samples from the Mabou-Ainslie and Central Cape Breton Subbasins


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LIST OF FIGURES (continued) Figure 19 . f. Sterane C27, C28, and C29 distributions of four oil-stains, and bitumen extracts from Lake Ainslie-88-1 well (Mabou-Ainslie Subbasin) and other three wells from Central Cape Breton Subbasins. Figure 20. Cross-plots of various parameters from Rock-Eval pyrolysis and TOC data of samples from Central Cape Breton Subbasins:

a. Remaining hydrocarbon potential vs. TOC showing the location of samples for the Central Cape Breton Subbasin; The oil- prone source rock is from Horton Group of Lake Ainslie 88-1 well

b. Kerogen Type (pseudo van Krevelen-Type) diagram showing the potential of sediments from various of the Central Cape Bretpon Subbasin c. Kerogen Type determination of various samples from Central Cape Breton Subbasin based on Tmax vs. hydrogen index

d. A plot of Tmax versus production index showing the position and HC Conversion of various samples from Central Cape Breton Subbasin

Figure 21. Maturity versus depth plot of various wells from the Central Cape Breton Subbasins Figure 22. Liquid chromatography data of four samples from Central Cape Breton Subbasins and Sydney Basin (data from Total Fina Report, 2000; permission from Total Inc., 2004) Figure 23. Gas chromatograms of the saturate fraction of the extract of various samples from the Central Cape Breton Subbasins a. Samples from three wells (i. AGR-34-77; ii. M-3; iii. LL-04) from the current contract from Central Subbasins. b. One sample from the Jubilee area well, Central Cape Breton Subbasin (data taken from Total Fina Contract, 2000; permission from Total Inc., 2004) c. One sample from the McIver Pt #1 well, Central Cape Breton Subbasin (data taken from Total Fina Contract, 2000; permission from Total Inc., 2004) d. Another sample from the McIver Pt #1 well, Central Cape Breton Subbasin (data taken from Total Fina Contract, 2000; permission from Total Inc., 2004)


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LIST OF FIGURES (continued) Figure 23 e. The crude oil sample from the Malagawatch M-9 well, Central Cape Breton Subbasin (data taken from Total Fina Contract, 2000; permission from Total Inc., 2004) Figure 24. Triterpane (m/z) and sterane (m/z 217) mass fragmentograms of oil-stains and crude oil from Central Cape Breton Subbasins a. Oil stain from ATG-34-77 well (357.8ft) b. Oil stain from Malagawatch M-3 well (1104.4m) c. Oil stains from LL-04 well (196.48m) d. Oil stain from ATG-17-77 well (218ft) (data taken from Total Fina Contract, 2000; permission from Total Inc., 2004) e. Oil stain from McIver Pt #1 well (149.7ft) (data taken from Total Fina Contract, 2000; permission from Total Inc., 2004) f. Oil stain of another sample from McIver Pt #1 well (896ft) (data taken from Total Fina Contract, 2000; permission from Total Inc., 2004) g. Crude oil from Malagawatch M-9 well (depth:?) (data taken from Total Fina Contract, 2000; permission from Total Inc., 2004) Figure 25. Cross-plots of various parameters from Rock-Eval pyrolysis and TOC data of samples from Sydney Basin (Mukhopadhyay, 2000 - from Total Fina Contract, 2000; permission from Total Inc., 2004) a. Remaining hydrocarbon potential vs. TOC showing the location

of samples b. Kerogen Type (pseudo van Krevelen-Type) diagram showing the

potential of sediments c. Kerogen Type determination of various samples based on Tmax vs. hydrogen index

d. A plot of Tmax versus production index showing the position and HC Conversion of various samples Figure 26. Maturity versus depth plots of various wells from the Sydney Basin (from Total Fina Contract, 2000; permission from Total Inc., 2004) a. Onshore Wells b. Offshore Wells Figure 27. Gas chromatograms of the saturate fraction of the extract of samples from two wells from the Sydney Basin: a. Ingonish #1 well; b. North Sydney F-24 (from Total Fina Contract, 2000; permission from Total Inc., 2004)


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LIST OF FIGURES (continued) Figure 28. Terpane (m/z 191) and sterane (217) mass fragmentograms of two samples from the Sydney Basin (from Total Fina Contract, 2000; permission from Total Inc., 2004) a. Oil stains from Ingonish #1 well b. Oil stain from the Windsor Group sediments of the North Sydney

G-24/F-24 (offshore) LIST OF APPENDICES Appendix A. Analytical Procedures – Petroleum Geochemistry Appendix B. Analytical Procedures – Reservoir Analysis (porosity and permeability) Appendix C. Previous Studies: Literature data and maps for petroleum geochemistry and reservoir Analysis a. Data and plots from Humblin (1989) b. Plots from Mukhopadhyay (1991) c. Data and Plot from Allen (1998) d. Data and Plots from Bibby and Shimeld (2000)

Tables

Table 1a: Summary of well information - Deep Wells >300mWestern and Southern Cape Breton Subbasins

Table 1b: Summary of Well Information - Deep Wells >300mBras d'Or Subbasin and Sydney Basin

Table 1b October 12, 2004

For: Nova Department of Energy Sample Details and Analytical Protocol(Current Contract)

Various Areas:Cores, Cuttings,

and Outcrop SamplesProject 2004-31: Cape Breton Project (March 31 - July 31, 2004)List of Samples for Geochemical Analyses and Porosity/Permeability Determination

Sample Area Well Name Sample Sample (well) Sample (well) Lithology Stratigraphy Staining Type TOC RE Extn VRo Por/PermNumber Type Depth (m or ft) Depth (m)

(original in well) (orig. or conv. to m.)1 Jubilee ATG-8-77 core 397m 397m Carbonate Windsor Group Oil Stained 1 1 0 0 02 Jubilee ATG-17-77 core 242m 242m Carbonate Windsor Group Oil Stains 0 0 0 0 03 Jubilee ATG-34-77 core 357.2-357.5ft 108.9-109m Carbonate Windsor Group Oil-soaked 1 0 1 0 04 Jubilee ATG-35-77 core 502ft 153m Carbonate Windsor Group Bitumen-impregnated 1 1 0 1 05 Jubilee ATG-49-78 core 237.5m 237.5m Limestone Windsor Gr.-MacumbeNo impregnation 0 0 0 0 06 Jubilee ATG-49-78 core 279m 279m Anhydrite Windsor Gr.-MacumbeOil-soaked 0 0 0 0 07 Jubilee ATG-49-78 core 292m 292m Limestone Windsor Gr.-MacumbeNo impregnation 1 1 0 1 08 Rankinville Rankinville #1 core 100m(?) 100m(?) Limestone Windsor Group Laminated 0 0 0 0 09 Rankinville Rankinville #2 core 69m (?) 69m (?) Limestone Windsor Group Laminated 0 0 0 0 0

10 Rankinville Rankinville #2 core 150m (?) 150m (?) Carbonate Windsor Group No impregnation 0 0 0 0 011 Orangedale 225-4 core 403.7m 403.7m Carbonate Windsor Group No impregnation 1 0 0 0 012 Orangedale 225-4 core 426.7m 426.7m Carbonate Windsor Group Bitumen-impregnated 1 1 0 1 013 Orangedale 225-5A core 991.77-991.80m 991.77-991.80m Carbonate Windsor Group Fractured 0 0 0 0 114 Orangedale 225-5A core 1024.7m 1024.7m Carbonate Windsor Group No impregnation 0 0 0 0 015 Orangedale 225-5A core 1044.5m 1044.5m Carbonate Windsor Group Bitumen-impregnated 1 1 0 1 016 Malagawatch M-5 core 359.06m 359.06m Carbonate Windsor Group Oil Stains 1 1 0 0 017 Malagawatch M-5A core 460.2-460.5m 460.2-460.5m Calc. Mudstone Windsor Group No impregnation 1 1 0 1 018 Malagawatch M-5A core 495.06m 495.06m Carbonate Windsor Group No impregnation 0 0 0 0 019 Malagawatch M-5A core 521m 521m Carbonate Windsor Group No impregnation 0 0 0 0 020 Malagawatch M-5A core 526.3m 526.3m Carbonate Windsor Group No impregnation 1 1 0 0 021 Malagawatch M-5A core 879m 879m Carbonate Windsor Group No impregnation 1 1 0 1 022 Malagawatch M-5A core 1026.3-1026.34m 1026.3-1026.34m Carbonate Windsor Group No impregnation 0 0 0 0 023 Malagawatch M-5A core 1036.8m 1036.8m Carbonate Windsor Group No impregnation 1 1 0 1 024 Malagawatch M-5A core 1187m 1187m Carbonate Windsor Group No impregnation 1 1 0 1 025 Malagawatch M-9 core 136.99-137.05m 136.99-137.05m Carbonate Windsor Group No impregnation 1 0 0 1 026 Malagawatch M-9 core 509.05-510m 509.05-510m Carbonate Windsor Group No impregnation 1 1 0 0 027 Malagawatch M-9 core 589m 589m Carbonate Windsor Group No impregnation 1 0 0 1 028 Malagawatch M-9 core 606.82-606.88m 606.82-606.88m Carbonate Windsor Group Bitumen-impregnated 1 1 0 0 029 Malagawatch M-9 core 1107m 1107m Carbonate Windsor Group With Potash minerals 1 0 0 1 030 Malagawatch M-7 core 746-746.03ft 227.4-227.41m Carbonate Windsor Group Fractured 0 0 0 0 131 Bras D'Or Bras D'Or 9-78 core 62ft 18.9m Carbonate Windsor Group No impregnation 1 0 0 1 0

Global Geoenergy Research Ltd.Table 2

1 October 26, 2004





32 Bras D'Or Bras D'Or 9-78 core 596ft 181.7m Carbonate Windsor Group No impregnation 1 1 0 1 033 McIver Point McIver Pt RW-1 core 1180m 1180m Carbonate Windsor Group No impregnation 0 0 0 0 034 Bras D'Or Bras D'Or 7-78 core 472ft 143.9m Carbonate Windsor Group No impregnation 1 1 0 0 035 Malagawatch M-3 core 1104.4m 1104.4m Carbonate Windsor Group Oil Soaked 1 1 0 0 036 Loch Lomond LL-04 core 74.5m 74.5m Shale Cumberland Group No impregnation 1 1 0 1 037 Loch Lomond LL-04 core 111m 111m Shaly Coal Cumberland Group No impregnation 1 0 0 0 038 Loch Lomond LL-04 core 134m 134m Sandstone Cumberland Group No impregnation 0 0 0 0 139 Loch Lomond LL-04 core 145.5m 145.5m Calc. Mudstone Mabou Group No impregnation 1 1 0 0 040 Loch Lomond LL-04 core 177m 177m Carbonate Windsor Group Fractured 0 0 0 0 041 Loch Lomond LL-04 core 196.48m 196.48m Carbonate Windsor Group Bitumen-impregnated 1 0 0 0 042 Loch Lomond LL-04 core 196.5m 196.5m Carbonate Windsor Group Laminated 1 1 0 1 043 Loch Lomond LL-04 core 275m 275m Shaly Carbonate Windsor Group Laminated 1 0 0 0 044 Loch Lomond LL-04 core 319.3m 319.3m Carbonate Windsor Group Oil-stained 1 1 0 0 045 Loch Lomond LL-04 core 319.4m 319.4m Carbonate Windsor Group Laminated 1 1 0 0 046 Loch Lomond LL-04 core 343.6m 343.6m Carbonate Windsor Group Bitumen-impregnated 1 0 0 0 047 Loch Lomond LL-04 core 376.5m 376.5m Carbonate Windsor Group Laminated 1 1 0 1 048 Loch Lomond Imperial 30-4 core 577m 577m Calc. Sandstone Mabou Group No impregnation 0 0 0 0 149 Loch Lomond Imperial 30-4 core 767m 767m Calc. Mudstone Windsor Group Bitumen-impregnated 1 1 0 1 050 Loch Lomond Imperial 30-4 core 847m 847m Carbonate Windsor Group No impregnation 1 1 0 0 051 Loch Lomond Imperial 30-4 core 952m 952m Carbonate Windsor Group Bitumen-impregnated 1 1 0 1 052 Lake Ainsle Lake Ainsle 88-1 core 35ft 10.7m Carbonate Windsor Group Laminated 1 1 0 1 0

53a Lake Ainsle Lake Ainsle 88-1 core 75ft 22.9m Shale Horton Group Laminated 1 1 1 0 053b Lake Ainsle Lake Ainsle 88-1 core 75.3ft 22.95m Sandstone Horton Group Oil-stained 1 0 0 1 1

54 Lake Ainsle Lake Ainsle 88-1 core 205ft 62.5m Shale Horton Group Laminated 1 1 0 1 055 Lake Ainsle NSDNR 314 core 50ft 15.2m Carbonate Windsor Gr.-MacumbeLake Ainsle 137.1 0 0 0 0 056 Lake Ainsle NSDNR 314 core 116ft 25.4m Shale Horton Group Lake Ainsle 137.1 0 0 0 0 057 Lake Ainsle NSDNR 314 core 131ft 39.9m Sandstone Horton Group Lake Ainsle 137.1 0 0 0 0 058 Lake Ainsle Mull River #1 cuttings 55m 55m Siltstone Horton Group No impregnation 0 0 0 1 059 Lake Ainsle Mull River #1 cuttings 230m 230m Shale Horton Group No impregnation 0 0 0 0 060 Lake Ainsle Mull River #1 cuttings 330m 330m Calc. Shale Horton Group No impregnation 1 1 0 1 061 Lake Ainsle Mull River #1 cuttings 410m 410m Shale Horton Group No impregnation 1 0 0 0 062 Lake Ainsle Mull River #1 cuttings 540m 540m Siltstone Horton Group No impregnation 0 0 0 0 0


2 October 26, 2004





63 Lake Ainsle Mull River #1 cuttings 630-635m 630-635m Shale Horton Group Black 1 0 0 1 064 Lake Ainsle Mull River #1 cuttings 770-775m 770-775m Shale Horton Group Black 1 0 0 1 065 Lake Ainsle Mull River #1 cuttings 915-920m 915-920m Shale Horton Group Black 1 1 0 1 066 Lake Ainsle Mull River #1 cuttings 1020-1025m 1020-1025m Shale Horton Group Black 1 0 0 0 067 Lake Ainsle Mull River #1 cuttings 1180m 1180m Shale Horton Group Black 1 1 0 1 068 Lake Ainsle Mull River #1 cuttings 1215m 1215m Silty Shale Horton Group Gray 1 0 0 0 069 Lake Ainsle Mull River #1 cuttings 1280m 1280m Shale Horton Group Black 0 0 0 0 070 Lake Ainsle Mull River #1 cuttings 1375m 1375m Shale Horton Group Black 1 1 0 0 071 Lake Ainsle Mull River #1 cuttings 1405m 1405m Shale Horton Group Black 1 1 0 1 072 Lake Ainsle Mull River #1 cuttings 1460m 1460m Shale Horton Group Gray 1 1 0 0 073 Lake Ainsle Mull River #1 cuttings 1475m 1475m Shale Horton Group Black 1 1 1 0 074 Lake Ainsle Mull River #1 cuttings 1502m 1502m Shale Horton Group Gray 1 1 0 1 075 Lake Ainsle Saarberg 8-1 core 90ft 27.4m Carbonate Windsor Group No impregnation 1 0 0 0 076 Lake Ainsle Saarberg 8-1 core 150ft 45.7m Sandstone Horton Group Fine-grained 0 0 0 0 077 Lake Ainsle Saarberg 8-2 core 143.5ft 43.7m Carbonate Windsor Group Bitumen-impregnated 0 0 0 0 078 Lake Ainsle Saarberg 8-3 core 121ft 36.9m Carbonate Windsor Group No impregnation 1 1 1 0 079 Lake Ainsle Saarberg 8-4 core 223ft 68m Carbonate Windsor Group Vuggy texture 0 0 0 0 180 Lake Ainsle Saarberg 8-4 core 240ft 73.2m Carbonate Windsor Group Black 1 0 0 0 081 Port Hood Mary #1 cuttings 460-475ft 140.2-144.8m Shale Cumberland Group Black 1 0 0 1 082 Port Hood Mary #1 cuttings 1275-1295ft 388.6-394.7m Shale Cumberland Group Black 1 0 0 0 083 Port Hood Mary #1 cuttings 1990-2010ft 606.6-612.6m Shale Cumberland Group Black 1 1 0 1 084 Port Hood Mary #1 cuttings 2375-2395ft 723.9-730m Shale Cumberland Group Black 1 0 0 0 085 Port Hood Mary #1 cuttings 3340-3360ft 1018-1024.1m Shale Mabou Group Black 0 0 0 0 086 Port Hood Mary #1 cuttings 3875-3890ft 1181.1-1185.7m Shale Mabou Group Black 1 1 0 0 087 Port Hood Mary #1 cuttings 4365-4370ft 1330.5-1332m Shaly Carbonate Windsor Group Black 1 1 0 0 088 Port Hood Mary #1 cuttings 5445-5450ft 1659.6-1661.2m Shaly Carbonate Windsor Group Gray 0 0 0 0 089 Port Hood Mary #1 cuttings 6835-6850ft 2083.3-2087.9m Calc. Shale Windsor Group Gray 0 0 0 1 090 Port Hood Port Hood #1 cuttings 180-190ft 54.9-57.9m Shale Cumberland Group Gray 0 0 0 0 091 Port Hood Port Hood #1 cuttings 1360-1380ft 414.5-420.6m Shale Cumberland Group Black 1 1 0 1 092 Port Hood Port Hood #1 cuttings 2910-2920ft 887-890m Shale Mabou Group Gray 0 0 0 0 093 Port Hood Port Hood #1 cuttings 3880-3890ft 1182.6-1185.7m Shale Mabou Group Black 1 0 0 0 094 Port Hood Port Hood #1 cuttings 4560-4580ft 1389.9-1396m Shale Mabou Group Black 1 0 0 0 0


3 October 26, 2004





95 Port Hood Port Hood #1 cuttings 5050-5070ft 1539.2-1545.3m Shale Mabou Group Black 1 0 0 0 096 Port Hood Port Hood #1 cuttings 5410-5440ft 1649-1658.1m Shale Mabou Group Black 0 0 0 0 097 Port Hood Port Hood #1 cuttings 6240-6250ft 1901.9-1905m Calc. Shale Mabou Group Gray 0 0 0 0 098 Port Hood Port Hood #1 cuttings 7300-7310ft 2225-2228.1m Shale+Carbonate Windsor Group Gray 0 0 0 0 099 Port Hood Port Hood #1 cuttings 8270-8280ft 2520.7-2523.7m Shaly Carbonate Windsor Group Gray 0 0 0 0 0

100 Port Hood Port Hood #1 cuttings 9100-9120ft 2773.7-2779.8m Carbonate Windsor Group Gray 0 0 0 0 0101 Port Hood Port Hood #1 cuttings 9460-9480ft 2883.4-2889.5m Shaly Carbonate Windsor Group Gray 0 0 0 0 0102 Port Hood Port Hood #1 cuttings 9820-9840ft 2993.10-2999.2m Shaly Carbonate Windsor Group Dark Gray 1 1 0 1 0103 Cleveland 227-2 core 2397ft 730.6m Shaly Carbonate Windsor Group Dark Gray 1 0 0 1 0104 Cleveland 227-2 core 2754ft 839.4m Salt+Carbonate Windsor Group Laminated 1 1 0 0 0105 Cleveland 227-2 core 2947ft 898.2m Shaly Carbonate Windsor Group Oil-stained 1 1 0 0 0106 Cleveland 227-2 core 3076ft 937.6m Calc. Shale Windsor Group Laminated 1 1 0 0 0107 Cleveland 227-2 core 3257ft 992.7m Carbonate Windsor Group Black 1 1 0 1 0108 Seaview SV #2 core 466ft 142m Carbonate Windsor Group Gray 0 0 0 0 0109 Seaview SV #2 core 652ft 198.7m Carbonate Windsor Group Black 0 0 0 0 0110 Seaview SV #2 core 879ft 267.9m Shaly Carbonate Windsor Group Black 0 0 0 0 0111 Seaview SV #2 core 2027ft 617.8m Calc. Shale Windsor Group Gray 0 0 0 0 0112 Maple Brook Maple Brook #1 core 38.5m 38.5m Shale ?? Black 0 0 0 0 0113 Maple Brook Maple Brook #1 core 126m 126m Calc. Shale ?? Black 0 0 0 0 0114 Maple Brook Maple Brook #1 core 238.5m 238.5m Calc. Shale ?? Black laminated 0 0 0 0 0115 Maple Brook Maple Brook #1 core 295m 295m Calc. Shale ?? Black 0 0 0 0 0116 Port Hood Is. Coal Mines Pt. surface 0 0 Carbonate Macumber Fm Black 0 0 0 0 0117 Port Hood Is. #4 surface 0 0 Carbonate Windsor Group Gray 0 0 0 0 0118 Port Hood Port Hood #1 core 2362ft 719.9m Carbonate Mabou Group Black laminated 1 1 0 1 0119 Port Hood Port Hood #1 core 6640ft 2023.9m Carbonate Windsor Group Black 1 1 0 1 0120 Port Hood Port Hood #1 core 7000ft 2133.6m Carbonate Windsor Group Gray 0 0 0 0 0121 Port Hood Port Hood #1 core 7552ft 2301.8m Fossiferous Carb. Windsor Group Gray to Black laminated 1 1 0 1 0122 Mabou Mabou #1 core 2061ft 628.2m Carbonate Windsor Group Black laminated 1 1 0 1 0123 Mabou Mabou #1 core 2420ft 737.6m Carbonate Windsor Group Gray to Black laminated 0 0 0 0 0124 Mabou Mabou #1 core 4468ft 1361.8m Calc. Shale Horton Group? Black 0 0 0 0 0125 Mabou Mabou #1 core 5114ft 1558.7m Shale Horton Group Black laminated 1 1 0 1 0126 Location 3 Ainslie Depocentre Outcrop Quartz Sandstone Strathlorne Fm (HortonCoarse Grained 0 0 0 0 1


4 October 26, 2004



and Outcrop Samples

Project 2004-31: Cape Breton Project (March 31 - July 31, 2004)List of Samples for Geochemical Analyses and Porosity/Permeability Determination


127 Location 14 Ainslie Depocentre Outcrop Sandstone Strathlorne or Ainslie FCoarse Grained 0 0 0 0 1128 Location 19 Ainslie Depocentre Outcrop Sandstone Cumberland Group (BoMedium Grained 0 0 0 0 1129 Location 20 Ainslie Depocentre Outcrop Sandstone Upper Part of Ainslie FFine-grained 0 0 0 0 1

Total Number of Samples for Each Analyses = 76 51 4 41 10TOC RE Extn VRo Por/Perm

(orig. or conv. to m.) = original depth in meter in core/cuttings samples or converted depth of core/cuttings in feet to meter


5 October 26, 2004

For: NSDOE TOC and ROCK-EVAL DATA Various Wells and Outcrops(Data from Current Contract)

Global Geoenergy Research Ltd. - Cape Breton Project

Top Bottom Median Leco NotesHGS Well Depth Depth Depth Client Sample TOC S1 S2 S3 Tmax Cal. Meas. HI OI S2/S3 S1/TOC PI Checks Pyrogram

No. Id. (ft/m) (ft./m) (ft./m) ID. Type (oC) %Ro %Ro04-2477-084538 ATG-8-77 397 397 1 core 1.41 2.39 3.93 0.27 432 0.62 278 19 15 169 0.38 c n04-2477-084539 ATG-34-77 357 357.5 357.35 3 core 0.2504-2477-084540 ATG-35-77 502 502 4 core 0.1704-2477-084541 ATG-49-78 292 292 7 core 0.31 0.15 0.32 0.15 437 * 0.71 105 49 2 49 0.32 n04-2477-084542 225-4 404 403.7 11 core 0.39 0.08 1.27 0.21 532 2.42 327 54 6 21 0.06 n04-2477-084543 225-4 427 426.7 12 core 4.33 1.49 6.43 0.25 433 0.63 148 6 26 34 0.19 n04-2477-084544 225-5A 1045 1044.5 15 core 0.97 0.35 0.79 0.38 440 0.76 81 39 2 36 0.31 n04-2477-084545 M-5 359 359.06 16 core 0.38 0.11 0.13 0.24 443 * 0.81 34 64 1 29 0.46 n04-2477-084546 M-5A 460 460.5 460.35 17 core 2.94 1.54 4.57 0.46 441 0.78 156 16 10 52 0.25 n04-2477-084547 M-5A 526 526.3 20 core 0.39 0.11 0.12 0.13 446 * 0.87 31 34 1 28 0.48 n04-2477-084548 M-5A 879 879 21 core 1.05 0.49 0.88 0.31 441 0.78 84 30 3 47 0.36 n04-2477-084549 M-5A 1037 1036.8 23 core 0.46 0.04 0.77 0.19 593 3.51 168 41 4 9 0.05 n04-2477-084550 M-5A 1187 1187 24 core 0.2004-2477-084551 M-9 137 137.05 137.02 25 core 1.10 0.36 0.60 0.36 442 0.80 55 33 2 33 0.38 n04-2477-084552 M-9 509 510 509.525 26 core 0.62 0.29 1.18 0.19 436 0.69 190 31 6 47 0.20 n04-2477-084553 M-9 589 589 27 core 0.67 0.30 0.50 0.31 435 0.67 74 46 2 44 0.38 n04-2477-084554 M-9 607 606.88 606.85 28 core 0.1804-2477-084555 M-9 1107 1107 29 core 0.88 0.13 1.16 0.29 583 3.33 131 33 4 15 0.10 n04-2477-084556 Bras D'Or 9-78 62 62 31 core 0.42 0.17 0.34 0.23 444 * 0.83 80 54 1 40 0.33 n04-2477-084557 Bras D'Or 9-78 596 596 32 core 0.1704-2477-084558 Bras D'Or 7-78 472 472 34 core 0.38 0.26 0.36 0.25 427 * 0.53 94 65 1 68 0.42 n04-2477-084559 M-3 1104 1104.4 35 core 5.69 2.56 6.59 0.66 448 0.90 116 12 10 45 0.28 c n04-2477-084560 LL-04 75 74.5 36 core 0.52 0.05 0.09 0.08 366 * -1.00 17 15 1 10 0.36 n04-2477-084561 LL-04 111 111 37 core 20.03 0.12 4.70 0.90 464 1.19 23 4 5 1 0.02 lc n;ltS2p04-2477-084562 LL-04 146 145.5 39 core 0.2604-2477-084563 LL-04 196 196.48 41 core 3.65 1.88 12.04 0.49 426 0.51 330 13 25 52 0.14 n04-2477-084564 LL-04 197 196.5 42 core 1.03 0.18 0.46 0.37 427 * 0.53 45 36 1 17 0.28 n04-2477-084565 LL-04 275 275 43 core 0.32 0.02 0.04 0.23 433 * 0.63 13 72 0 6 0.33 n04-2477-084566 LL-04 319 319.3 44 core 1.62 0.27 1.68 0.24 437 0.71 104 15 7 17 0.14 n04-2477-084567 LL-04 319 319.4 45 core 0.58 0.06 0.26 0.20 430 * 0.58 45 34 1 10 0.19 n04-2477-084568 LL-04 344 343.6 46 core 0.33 0.04 0.03 0.21 407 * 0.17 9 63 0 12 0.57 n04-2477-084569 LL-04 377 376.5 47 core 0.0904-2477-084570 Imperial 30-4 767 767 49 core 0.44 0.07 0.11 0.20 432 * 0.62 25 45 1 16 0.39 n04-2477-084571 Imperial 30-4 847 847 50 core 0.36 0.10 0.39 0.16 436 * 0.69 108 44 2 28 0.20 n04-2477-084572 Imperial 30-4 952 952 51 core 2.03 0.35 1.61 0.28 432 0.62 79 14 6 17 0.18 n04-2477-084573 Lake Ainsle 88-1 35 35 52 core 0.68 0.17 0.49 0.28 454 * 1.01 72 41 2 25 0.26 n04-2477-084574 Lake Ainsle 88-1 75 75 53 core 1.48 5.19 8.77 0.31 425 0.49 592 21 28 350 0.37 n04-2477-084575 Lake Ainsle 88-1 205 205 54 core 0.50 0.07 0.23 0.17 441 * 0.78 46 34 1 14 0.23 n04-2477-084576 Mull River #1 330 330 60 cuttings 0.39 0.02 0.06 0.12 445 * 0.85 15 31 1 5 0.25 n04-2477-084577 Mull River #1 410 410 61 cuttings 0.43 0.02 0.07 0.17 448 * 0.90 16 40 0 5 0.22 n04-2477-084578 Mull River #1 630 635 632.5 63 cuttings 0.1204-2477-084579 Mull River #1 770 775 772.5 64 cuttings 0.1304-2477-084580 Mull River #1 915 920 917.5 65 cuttings 0.1704-2477-084581 Mull River #1 1020 1025 1022.5 66 cuttings 0.30 0.01 0.01 0.09 386 * -1.00 3 30 0 3 0.50 n04-2477-084582 Mull River #1 1180 1180 67 cuttings 0.2204-2477-084583 Mull River #1 1215 1215 68 cuttings 0.1604-2477-084584 Mull River #1 1375 1375 70 cuttings 0.25 0.02 0.02 0.13 -1 * -1.00 8 52 0 8 0.50 lc n04-2477-084585 Mull River #1 1405 1405 71 cuttings 0.31 0.03 0.04 0.10 360 * -1.00 13 32 0 10 0.43 n04-2477-084586 Mull River #1 1475 1475 73 cuttings 0.1904-2477-084587 Mull River #1 1502 1502 74 cuttings 0.24 0.02 0.02 0.11 308 * -1.00 8 46 0 8 0.50 n04-2477-084588 Saarberg 8-1 90 90 75 core 0.2004-2477-084589 Saarberg 8-3 121 121 78 core 0.1204-2477-084590 Saarberg 8-4 240 240 80 core 0.1604-2477-084591 Mary #1 460 475 467.5 81 cuttings 0.25 0.07 0.08 0.19 301 * -1.00 31 75 0 28 0.47 n04-2477-084592 Mary #1 1275 1295 1285 82 cuttings 0.2104-2477-084593 Mary #1 1990 2010 2000 83 cuttings 0.2104-2477-084594 Mary #1 2375 2395 2385 84 cuttings 0.2404-2477-084595 Mary #1 3875 3890 3882.5 86 cuttings 0.26 0.15 0.26 0.19 376 * -1.00 100 73 1 58 0.37 n04-2477-084596 Mary #1 4365 4370 4367.5 87 cuttings 0.21

Job: 2004-31

From: Global Geoenergy Research Ltd. Table 3 October 26, 2004

For: NSDOE TOC and ROCK-EVAL DATA Various Wells and Outcrops(Data from Current Contract)



No. Id. (ft/m) (ft./m) (ft./m) ID. Type (oC) %Ro %Ro

Job: 2004-31

04-2477-084597 Imperial Port Hood #1 1360 1380 1370 91 cuttings 0.33 0.09 0.05 0.12 322 * -1.00 15 37 0 27 0.64 n04-2477-084598 Imperial Port Hood #1 3880 3890 3885 93 cuttings 0.2304-2477-084599 Imperial Port Hood #1 4560 4580 4570 94 cuttings 0.2304-2477-084600 Imperial Port Hood #1 5050 5070 5060 95 cuttings 0.26 0.08 0.05 0.16 424 * 0.47 19 61 0 30 0.62 n04-2477-084601 Imperial Port Hood #1 9820 9840 9830 102 cuttings 0.1804-2477-084602 227-2 2397 2397 103 core 0.50 0.04 0.00 0.38 -1 * -1.00 0 76 0 8 1.00 n04-2477-084603 227-2 2754 2754 104 core 0.49 0.19 0.12 0.66 312 * -1.00 25 136 0 39 0.61 c n04-2477-084604 227-2 2947 2947 105 core 4.82 0.38 0.05 0.61 -1 * -1.00 1 13 0 8 0.88 lc n04-2477-084605 227-2 3076 3076 106 core 1.52 0.17 0.01 0.50 -1 * -1.00 1 33 0 11 0.94 n04-2477-084606 227-2 3257 3257 107 core 0.31 0.05 0.01 0.20 -1 * -1.00 3 64 0 16 0.83 n04-2477-084607 Imperial Port Hood #1 2362 2362 118 core 0.50 0.02 0.03 0.24 421 * 0.42 6 48 0 4 0.40 n04-2477-084608 Imperial Port Hood #1 6640 6640 119 core 0.1704-2477-084609 Imperial Port Hood #1 7552 7552 121 core 0.30 0.06 0.07 0.31 370 * -1.00 24 104 0 20 0.46 n04-2477-084610 Imperial Mabou #1 2061 2061 122 core 0.1604-2477-084611 Imperial Mabou #1 4468 4468 124 core 0.29 0.02 0.01 0.13 300 * -1.00 3 45 0 7 0.67 n04-2477-084612 Imperial Mabou #1 5114 5114 125 core 0.42 0.02 0.03 0.07 383 * -1.00 7 17 0 5 0.40 c n

Note: "-1" indicates not measured or meaningless ratio

* Tmax data not reliable due to poor S2 peak

TOC = weight percent organic carbon in rockS1, S2 = mg hydrocarbons per gram of rockS3 = mg carbon dioxide per gram of rockTmax = oC

HI = hydrogen index = S2 x 100 / TOCOI = oxygen index = S3 x 100 / TOCS1/TOC = normalized oil content = S1 x 100 / TOCPI = production index = S1 / (S1+S2)Cal. %Ro = calculated vitrinite reflectance based on TmaxMeasured %Ro = measured vitrinite reflectance

Notes:

c = analysis checked and confirmed

Pyrogram:n=normalltS2sh = low temperature S2 shoulderltS2p = low temperature S2 peakhtS2p = high temperature S2 peakf = flat S2 peak


For: NSDOE TOC and ROCK-EVAL DATA(Data from Current Contract)

Various Wells and Outcrops(Western Cape Breton Subbasins)



No. Id. (ft/m) (ft./m) (ft./m) ID. Type (oC) %Ro %Ro04-2477-084573 Lake Ainsle 88-1 35 35 52 core 0.68 0.17 0.49 0.28 454 * 1.01 72 41 2 25 0.26 n04-2477-084574 Lake Ainsle 88-1 75 75 53 core 1.48 5.19 8.77 0.31 425 0.49 592 21 28 350 0.37 n04-2477-084575 Lake Ainsle 88-1 205 205 54 core 0.50 0.07 0.23 0.17 441 * 0.78 46 34 1 14 0.23 n04-2477-084576 Mull River #1 330 330 60 cuttings 0.39 0.02 0.06 0.12 445 * 0.85 15 31 1 5 0.25 n04-2477-084577 Mull River #1 410 410 61 cuttings 0.43 0.02 0.07 0.17 448 * 0.90 16 40 0 5 0.22 n04-2477-084578 Mull River #1 630 635 632.5 63 cuttings 0.1204-2477-084579 Mull River #1 770 775 772.5 64 cuttings 0.1304-2477-084580 Mull River #1 915 920 917.5 65 cuttings 0.1704-2477-084581 Mull River #1 1020 1025 1022.5 66 cuttings 0.30 0.01 0.01 0.09 386 * -1.00 3 30 0 3 0.50 n04-2477-084582 Mull River #1 1180 1180 67 cuttings 0.2204-2477-084583 Mull River #1 1215 1215 68 cuttings 0.1604-2477-084584 Mull River #1 1375 1375 70 cuttings 0.25 0.02 0.02 0.13 -1 * -1.00 8 52 0 8 0.50 lc n04-2477-084585 Mull River #1 1405 1405 71 cuttings 0.31 0.03 0.04 0.10 360 * -1.00 13 32 0 10 0.43 n04-2477-084586 Mull River #1 1475 1475 73 cuttings 0.1904-2477-084587 Mull River #1 1502 1502 74 cuttings 0.24 0.02 0.02 0.11 308 * -1.00 8 46 0 8 0.50 n04-2477-084588 Saarberg 8-1 90 90 75 core 0.2004-2477-084589 Saarberg 8-3 121 121 78 core 0.1204-2477-084590 Saarberg 8-4 240 240 80 core 0.1604-2477-084591 Mary #1 460 475 467.5 81 cuttings 0.25 0.07 0.08 0.19 301 * -1.00 31 75 0 28 0.47 n04-2477-084592 Mary #1 1275 1295 1285 82 cuttings 0.2104-2477-084593 Mary #1 1990 2010 2000 83 cuttings 0.2104-2477-084594 Mary #1 2375 2395 2385 84 cuttings 0.2404-2477-084595 Mary #1 3875 3890 3882.5 86 cuttings 0.26 0.15 0.26 0.19 376 * -1.00 100 73 1 58 0.37 n04-2477-084596 Mary #1 4365 4370 4367.5 87 cuttings 0.2104-2477-084597 Imperial Port Hood #1 1360 1380 1370 91 cuttings 0.33 0.09 0.05 0.12 322 * -1.00 15 37 0 27 0.64 n04-2477-084598 Imperial Port Hood #1 3880 3890 3885 93 cuttings 0.2304-2477-084599 Imperial Port Hood #1 4560 4580 4570 94 cuttings 0.2304-2477-084600 Imperial Port Hood #1 5050 5070 5060 95 cuttings 0.26 0.08 0.05 0.16 424 * 0.47 19 61 0 30 0.62 n04-2477-084601 Imperial Port Hood #1 9820 9840 9830 102 cuttings 0.1804-2477-084607 Imperial Port Hood #1 2362 2362 118 core 0.50 0.02 0.03 0.24 421 * 0.42 6 48 0 4 0.40 n04-2477-084608 Imperial Port Hood #1 6640 6640 119 core 0.1704-2477-084609 Imperial Port Hood #1 7552 7552 121 core 0.30 0.06 0.07 0.31 370 * -1.00 24 104 0 20 0.46 n04-2477-084610 Imperial Mabou #1 2061 2061 122 core 0.1604-2477-084611 Imperial Mabou #1 4468 4468 124 core 0.29 0.02 0.01 0.13 300 * -1.00 3 45 0 7 0.67 n04-2477-084612 Imperial Mabou #1 5114 5114 125 core 0.42 0.02 0.03 0.07 383 * -1.00 7 17 0 5 0.40 c n

Job: 2004-31





Notes:



From: Global Geoenergy Research Ltd. Table 3a October 26, 2004

For: NSDOE TOC and ROCK-EVAL DATA(Data from Current Contract from Mukhopadhyay, 2000)

(Permission from Total Inc., 2004)

Various Wells (Central Cape Breton Subbasins)



No. Id. (ft/m) (ft./m) (ft./m) ID. Type (oC) %Ro %Ro04-2477-084538 ATG-8-77 397 397 1 core 1.41 2.39 3.93 0.27 432 278 19 15 169 0.38 c n

GG000061 ATG-17-77 218 218 Total Fina 218.00 0.16GG000062 ATG-19-77 406 Total Fina 406.70 0.31GG000032 ATG-19-77 446 Total Fina 446.00 0.49 3.17 1.88 0.38 407.00 383.67 77.55 4.95 646.94 0.63

04-2477-084541 ATG-49-78 292 292 7 core 0.31 0.15 0.32 0.15 437 * 105 49 2 49 0.32 n04-2477-084542 225-4 404 403.7 11 core 0.39 0.08 1.27 0.21 532 327 54 6 21 0.06 n04-2477-084543 225-4 427 426.7 12 core 4.33 1.49 6.43 0.25 433 148 6 26 34 0.19 n04-2477-084544 225-5A 1045 1044.5 15 core 0.97 0.35 0.79 0.38 440 81 39 2 36 0.31 n04-2477-084545 M-5 359 359.06 16 core 0.38 0.11 0.13 0.24 443 * 34 64 1 29 0.46 n04-2477-084546 M-5A 460 460.5 460.35 17 core 2.94 1.54 4.57 0.46 441 156 16 10 52 0.25 n04-2477-084547 M-5A 526 526.3 20 core 0.39 0.11 0.12 0.13 446 * 31 34 1 28 0.48 n04-2477-084548 M-5A 879 879 21 core 1.05 0.49 0.88 0.31 441 84 30 3 47 0.36 n04-2477-084549 M-5A 1037 1036.8 23 core 0.46 0.04 0.77 0.19 593 168 41 4 9 0.05 n04-2477-084551 M-9 137 137.05 137.02 25 core 1.10 0.36 0.60 0.36 442 55 33 2 33 0.38 n04-2477-084552 M-9 509 510 509.525 26 core 0.62 0.29 1.18 0.19 436 190 31 6 47 0.20 n04-2477-084553 M-9 589 589 27 core 0.67 0.30 0.50 0.31 435 74 46 2 44 0.38 n04-2477-084555 M-9 1107 1107 29 core 0.88 0.13 1.16 0.29 583 131 33 4 15 0.10 n04-2477-084559 M-3 1104 1104.4 35 core 5.69 2.56 6.59 0.66 448 116 12 10 45 0.28 c n04-2477-084556 Bras D'Or 9-78 62 62 31 core 0.42 0.17 0.34 0.23 444 * 80 54 1 40 0.33 n04-2477-084558 Bras D'Or 7-78 472 472 34 core 0.38 0.26 0.36 0.25 427 * 94 65 1 68 0.42 n

GG000001 LL-1-91 656 656.00 0.10GG000002 LL-1-91 935 935.00 2.12 0.11 2.01 0.55 433.00 3.65 5.19 0.05GG000003 LL-1-91 1212.5 1212.50 0.41GG000004 LL-1-91 1455 1455.00 0.06

04-2477-084560 LL-04 75 74.5 36 core 0.52 0.05 0.09 0.08 366 * 17 15 1 10 0.36 n04-2477-084561 LL-04 111 111 37 core 20.03 0.12 4.70 0.90 464 23 4 5 1 0.02 lc n;ltS2p04-2477-084563 LL-04 196 196.48 41 core 3.65 1.88 12.04 0.49 426 330 13 25 52 0.14 n04-2477-084564 LL-04 197 196.5 42 core 1.03 0.18 0.46 0.37 427 * 45 36 1 17 0.28 n04-2477-084565 LL-04 275 275 43 core 0.32 0.02 0.04 0.23 433 * 13 72 0 6 0.33 n04-2477-084566 LL-04 319 319.3 44 core 1.62 0.27 1.68 0.24 437 104 15 7 17 0.14 n04-2477-084567 LL-04 319 319.4 45 core 0.58 0.06 0.26 0.20 430 * 45 34 1 10 0.19 n04-2477-084568 LL-04 344 343.6 46 core 0.33 0.04 0.03 0.21 407 * 9 63 0 12 0.57 n04-2477-084570 Imperial 30-4 767 767 49 core 0.44 0.07 0.11 0.20 432 * 25 45 1 16 0.39 n04-2477-084571 Imperial 30-4 847 847 50 core 0.36 0.10 0.39 0.16 436 * 108 44 2 28 0.20 n04-2477-084572 Imperial 30-4 952 952 51 core 2.03 0.35 1.61 0.28 432 79 14 6 17 0.18 n04-2477-084602 Cleveland 227-2 2397 2397 103 core 0.50 0.04 0.00 0.38 400 0 76 0 8 1.0004-2477-084603 Cleveland 227-2 2754 2754 104 core 0.49 0.19 0.12 0.66 312 25 136 0 39 0.6104-2477-084604 Cleveland 227-2 2947 2947 105 core 4.82 0.38 0.05 0.61 400 1 13 0 8 0.8804-2477-084605 Cleveland 227-2 3076 3076 106 core 1.52 0.17 0.01 0.50 400 1 33 0 11 0.9404-2477-084606 Cleveland 227-2 3257 3257 107 core 0.31 0.05 0.01 0.20 400 3 64 0 16 0.83

GG000064 Leiches Creek #3 Total Fina 13.50 0.18GG000065 Kaiser #F-5 Total Fina 154.00 0.56 0.02 0.19 0.37 443.00 33.93 66.07 0.51 3.57 0.10GG000066 Kaiser #F-3 Total Fina 187.00 0.67 0.02 0.08 0.31 455.00 11.94 46.27 0.26 2.99 0.20GG000067 McIvor Pt #R-1 Total Fina 78.85 0.72 0.10 0.95 0.03 434.00 131.94 4.17 31.67 13.89 0.10GG000068 McIvor Pt #R-1 Total Fina 149.70 0.87 0.10 2.67 0.10 433.00 306.90 11.49 26.70 11.49 0.04GG000069 McIvor Pt #R-1 Total Fina 173.00 0.50 0.10 0.32 0.19 435.00 64.00 38.00 1.68 20.00 0.24GG000070 McIvor Pt #R-1 Total Fina 645.50 1.32 0.67 2.01 0.46 435.00 152.27 34.85 4.37 50.76 0.25GG000071 McIvor Pt #R-1 Total Fina 896.00 0.41GG000072 McIvor Pt #R-1 Total Fina 898.10 0.59 0.26 0.59 0.12 437.00 100.00 20.34 4.92 44.07 0.31GG000073 Cerro Mining #71-3 Total Fina 47.00 0.14GG000074 Cerro Mining #71-3 Total Fina 356.00 0.32GG000075 Cerro Mining #71-3 Total Fina 411.50 0.51 0.11 0.18 0.03 422.00 35.29 5.88 6.00 21.57 0.38GG000076 Cerro Mining #71-3 Total Fina 669.00 0.26

Job: 2004-31

From: Global Geoenergy Research Ltd. Geochem - Table 3b August 12, 2004

For: NSDOE TOC and ROCK-EVAL DATA(Data from Current Contract from Mukhopadhyay, 2000)

(Permission from Total Inc., 2004)





Job: 2004-31





Notes:



From: Global Geoenergy Research Ltd. Geochem - Table 3b August 12, 2004

For: NSDOE TOC and ROCK-EVAL DATA(Data from Mukhopadhyay, 2000)(Permission from Total Inc., 2004)

Various Wells and Outcrops(Sydney Subbasin)




GG000005 NS G-24 1780 1780.00 3.15 0.16 2.19 0.49 432.00 69.52 15.56 4.47 5.08 0.07GG000006 NS G-24 2640 2640.00 36.43 10.22 71.52 4.03 443.00 196.32 11.06 17.75 28.05 0.13GG000007 NS G-24 3155 3155.00 1.80 0.31 1.65 1.01 449.00 91.67 56.11 1.63 17.22 0.16GG000008 NS G-24 3179 3179.00 77.15GG000009 NS G-24 3639 3639.00 0.95 0.12 0.54 0.51 465.00 56.84 53.68 1.06 12.63 0.18GG000010 NS G-24 4190 4190.00 5.51 0.76 6.03 0.74 458.00 109.44 13.43 8.15 13.79 0.11GG000011 NS G-24 4220 4220.00 4.33 0.79 6.48 0.66 447.00 149.65 15.24 9.82 18.24 0.11GG000012 NS G-24 4455 4455.00 0.46 0.09 0.37 0.24 482.00 80.43 52.17 1.54 19.57 0.20GG000013 NS G-24 4600 4610.00 2.58 0.33 1.70 0.36 462.00 65.89 13.95 4.72 12.79 0.16GG000014 NS G-24 4940 4950.00 0.73 0.17 0.55 0.30 484.00 75.34 41.10 1.83 23.29 0.24GG000015 NS G-24 5020 5040.00 0.63 0.12 0.33 0.34 484.00 52.38 53.97 0.97 19.05 0.27GG000016 NS G-24 5220 5230.00 0.53 0.12 0.47 0.32 480.00 88.68 60.38 1.47 22.64 0.20GG000017 NS G-24 5370 5380.00 0.34GG000018 NS G-24 5410 5420.00 0.31GG000019 NS G-24 5520 5530.00 0.29GG000020 NS G-24 5550 5560.00 0.37 0.01 0.10 0.31 486.00 27.03 83.78 0.32 2.70 0.09GG000021 NS P-05 2680 2680.00 12.97 2.65 25.92 1.10 442.00 199.85 8.48 23.56 20.43 0.09GG000022 NS P-05 2990 3000.00 5.38 0.85 8.42 0.72 444.00 156.51 13.38 11.69 15.80 0.09GG000023 NS P-05 3180 3190.00 21.11 4.40 46.12 1.24 450.00 218.47 5.87 37.19 20.84 0.09GG000024 NS P-05 3410 3430.00 1.65 0.17 1.11 0.51 451.00 67.27 30.91 2.18 10.30 0.13GG000025 NS P-05 3660 3660.00 2.80 0.35 2.69 1.11 450.00 96.07 39.64 2.42 12.50 0.12GG000026 NS P-05 4360 4370.00 0.46 0.06 0.53 0.37 456.00 115.22 80.43 1.43 13.04 0.10GG000027 NS P-05 4510 4510.00 1.59 0.35 1.06 0.55 452.00 66.67 34.59 1.93 22.01 0.25GG000028 NS P-05 4830 4840.00 0.36 0.04 0.24 0.27 493.00 66.67 75.00 0.89 11.11 0.14GG000029 NS P-05 5090 5100.00 0.20GG000030 NS P-05 5300 5310.00 0.08GG000031 NS P-05 5420 5430.00 0.13GG000033 SYD 82-1 591.5 591.50 11.74 0.13 5.10 0.93 429.00 43.44 7.92 5.48 1.11 0.02GG000034 ING #1 55 55.00 1.17 0.37 2.62 0.72 425.00 223.93 61.54 3.64 31.62 0.12GG000035 ING #1 131 131.00 2.00 0.81 6.53 1.04 422.00 326.50 52.00 6.28 40.50 0.11GG000036 ING #4 74 74.00 0.92 0.36 2.50 0.66 425.00 271.74 71.74 3.79 39.13 0.13GG000037 PE-83-1 683.1 683.10 0.03GG000038 PE-84-1 133.3 133.30 0.46GG000039 PE-84-1 136.5 136.50 0.48 0.05 0.20 0.48 432.00 41.67 100.00 0.42 10.42 0.20GG000040 PE-84-1 153.2 153.20 0.62 0.09 0.50 0.55 428.00 80.65 88.71 0.91 14.52 0.15

GG000041 PE-84-1 164.2 164.20 0.67 0.12 0.52 0.20 429.00 77.61 29.85 2.60 17.91 0.19GG000042 KEW 85-1 35.7 35.70 1.61 0.02 0.73 0.24 457.00 45.34 14.91 3.04 1.24 0.03GG000043 KEW 85-1 52.8 52.80 0.93 0.02 0.21 0.25 470.00 22.58 26.88 0.84 2.15 0.09GG000044 KEW 85-1 112.5 112.50 1.57 0.21 14.19 0.40 434.00 903.82 25.48 35.48 13.38 0.01GG000045 KEW 85-1 177 177.00 0.60 0.10 4.87 0.36 434.00 811.67 60.00 13.53 16.67 0.02GG000046 KEW 85-1 251.7 251.70 0.08GG000047 WR-84-1 86.1 86.10 0.55 0.29 0.30 0.45 419.00 54.55 81.82 0.67 52.73 0.49GG000048 WR-84-1 95.8 95.80 0.35GG000049 WR-84-1 97.2 97.20 0.31GG000050 WR-84-1 112.5 112.50 0.46GG000051 WR-84-1 237.4 237.45 0.38GG000052 WR-84-1 238.7 238.70 2.12 0.78 5.52 0.60 436.00 260.38 28.30 9.20 36.79 0.12GG000053 WR-84-1 355 355.00 1.07 0.10 0.69 0.78 434.00 64.49 72.90 0.88 9.35 0.13GG000054 WR-84-1 375.2 375.20 0.52 0.07 0.30 0.30 480.00 57.69 57.69 1.00 13.46 0.19GG000055 WR-84-1 378.5 378.50 0.66 0.07 0.39 0.36 433.00 59.09 54.55 1.08 10.61 0.15GG000056 WR-84-1 393.5 393.50 0.22GG000057 WR-84-1 535.5 535.50 0.03GG000058 WR-84-1 536 536.00 0.14GG000059 WR-84-1 549.8 549.80 0.12GG000060 WR-84-1 550.5 550.50 0.25 0.02 0.03 0.13 517.00 12.00 52.00 0.23 8.00 0.40GG000063 NS G-24 4473.5 4473.50 0.04GG000077 Leiches Creek #1 65.00 0.71 0.24 0.83 0.19 435.00 116.90 26.76 4.37 33.80 0.22GG000078 Leiches Creek #1 78.00 0.25

Job: 2004-31

From: Global Geoenergy Research Ltd. Table 3c October 26, 2004

For: NSDOE TOC and ROCK-EVAL DATA(Data from Mukhopadhyay, 2000)(Permission from Total Inc., 2004)

Various Wells and Outcrops(Sydney Subbasin)




Job: 2004-31

GG000079 Leiches Creek #4 58.00 0.13GG000080 Leiches Creek #4 73.00 0.14GG000081 DME #1 (6610) McA.Lake 77.00 9.28 0.20 6.60 0.59 439.00 71.12 6.36 11.19 2.16 0.03GG000082 DME #2 (6610) McA.Lake 140.00 3.30 0.10 1.19 0.15 446.00 36.06 4.55 7.93 3.03 0.08GG000083 DME #2 (6610) McA.Lake 250.50 1.67 0.02 0.21 0.27 504.00 12.57 16.17 0.78 1.20 0.09





Notes:



From: Global Geoenergy Research Ltd. Table 3c October 26, 2004

For: Nova Department of Energy Vitrinite Reflectance data(Current Contract)


and Outcrop SamplesProject 2004-31: Cape Breton Project (March 31 - July 31, 2004)Vitrinite Reflectance Data: This Contract

Sample Area Well Name Sample Sample Vitrinite Reflectance Data Lithology Stratigraphy SubbasinsNumber Type Depth (m) VRo (%) Std.Dev Total Grains Autochthonous Total VRo

(Mean) Vitrinite Grains (all grains)4 Jubilee ATG-35-77 core 153m 0.56 0.07 50 19 0.74 Carbonate Windsor Group Central CB7 Jubilee ATG-49-78 core 292m 0.56 0.03 50 9 0.88 Limestone Macumber Fm Central CB

12 Orangedale 225-4 core 426.7m 0.59 0.05 50 40 0.65 Carbonate Windsor Group Central CB15 Orangedale 225-5A core 1044.5m 0.79 0.06 50 27 0.78 Carbonate Windsor Group Central CB17 Malagawatch M-5A core 460.2-460.5m 0.87 0.06 50 46 0.87 Calc. Mudstone Windsor Group Central CB21 Malagawatch M-5A core 879m 0.96 0.06 50 38 0.96 Carbonate Windsor Group Central CB23 Malagawatch M-5A core 1036.8m 1.02 0.09 50 17 1.06 Carbonate Windsor Group Central CB24 Malagawatch M-5A core 1187m 1.05 0.17 10 8 0.96 Carbonate Windsor Group Central CB25 Malagawatch M-9 core 136.99-137.05m 0.83 0.05 50 44 0.85 Carbonate Windsor Group Central CB27 Malagawatch M-9 core 589m 0.89 0.09 50 25 0.95 Carbonate Windsor Group Central CB29 Malagawatch M-9 core 1107m 0.99 0.06 50 19 1.1 Carbonate Windsor Group Central CB31 Bras D'Or Bras D'Or 9-78 core 18.9m 0.54 0.06 51 10 0.73 Carbonate Windsor Group Central CB32 Bras D'Or Bras D'Or 9-78 core 181.7m 0.6 0.07 50 23 0.82 Carbonate Windsor Group Central CB37 Loch Lomond LL-04 core 111m 0.75 0.05 50 26 0.79 Shaly Coal Cumberland Group Central CB42 Loch Lomond LL-04 core 196.5m 0.82 0.05 50 48 0.83 Carbonate Windsor Group Central CB47 Loch Lomond LL-04 core 376.5m 0.88 0.09 7 2 1.34 Carbonate Windsor Group Central CB49 Loch Lomond Imperial 30-4 core 767m 0.73 0.04 50 17 0.83 Calc. Mudstone Windsor Group Central CB51 Loch Lomond Imperial 30-4 core 952m 0.75 0.04 51 12 0.64 Carbonate Windsor Group Central CB52 Lake Ainsle Lake Ainsle 88-1 core 10.7m 0.62 0.02 50 41 0.72 Carbonate Windsor Group Western CB54 Lake Ainsle Lake Ainsle 88-1 core 62.5m 0.79 0.13 51 17 1.05 Shale Horton Group Western CB58 Lake Ainsle Mull River #1 cuttings 55m 0.8 0.07 50 12 0.98 Siltstone Horton Group Western CB60 Lake Ainsle Mull River #1 cuttings 330m 0.84 0.1 50 9 1.21 Calc. Shale Horton Group Western CB63 Lake Ainsle Mull River #1 cuttings 630-635m 0.93 0.07 51 15 1.14 Shale Horton Group Western CB64 Lake Ainsle Mull River #1 cuttings 770-775m 1 0.08 51 21 1.16 Shale Horton Group Western CB65 Lake Ainsle Mull River #1 cuttings 915-920m 1.01 0.09 50 11 1.36 Shale Horton Group Western CB67 Lake Ainsle Mull River #1 cuttings 1180m 0.99 0.1 50 21 1.12 Shale Horton Group Western CB71 Lake Ainsle Mull River #1 cuttings 1405m 0.95 0.13 51 14 1.19 Shale Horton Group Western CB74 Lake Ainsle Mull River #1 cuttings 1502m 0.89 0.12 50 15 1.16 Shale Horton Group Western CB81 Port Hood Mary #1 cuttings 140.2m 1.02 0.16 50 13 1.44 Shale Cumberland Group Western CB83 Port Hood Mary #1 cuttings 606.6m 1.37 0.11 50 17 1.56 Shale Cumberland Group Western CB89 Port Hood Mary #1 cuttings 2083.3m 1.4 0.14 51 23 1.57 Calc. Shale Windsor Group Western CB

Global Geoenergy Research Ltd.Table 4a

1 October 26, 2004

For: Nova Department of Energy Vitrinite Reflectance data(Current Contract)


and Outcrop Samples

Project 2004-31: Cape Breton Project (March 31 - July 31, 2004)Vitrinite Reflectance Data: This Contract

Sample Area Well Name Sample Sample Vitrinite Reflectance Data Lithology Stratigraphy SubbasinsNumber Type Depth (m) VRo (%) Std.Dev Total Grains Autochthonous Total VRo

91 Port Hood Port Hood #1 cuttings 414.5m 1.58 0.1 50 34 1.62 Shale Cumberland Group Western CB118 Port Hood Port Hood #1 core 719.9m 1.18 0.16 50 9 1.54 Carbonate Mabou Group Western CB119 Port Hood Port Hood #1 core 2023.9m 2.18 0.32 41 14 2.62 Carbonate Windsor Group Western CB121 Port Hood Port Hood #1 core 2301.8m 1.54 0.21 50 48 1.51 Fossiferous Carb. Windsor Group Western CB102 Port Hood Port Hood #1 cuttings 2993.1m 1.42 0.12 51 24 1.53 Shaly Carbonate Windsor Group Western CB103 Cleveland 227-2 core 730.6m 2.78 0.14 50 26 2.7 Shaly Carbonate Windsor Group Central CB107 Cleveland 227-2 core 992.7m 2.44 0.09 52 48 2.44 Carbonate Windsor Group Central CB122 Mabou Mabou #1 core 628.2m 2.25 0.12 50 31 2.35 Carbonate Windsor Group Western CB125 Mabou Mabou #1 core 1558.7m 1.67 0.1 50 15 1.88 Shale Horton Group Western CB

Global Geoenergy Research Ltd.Table 4a

2 October 26, 2004

For: NSDOE Vitrinite Reflectance Data(from Mukhopadhyay, 2000)

(with permission from Total Inc. 2004)

Sydney Basin andCentral Cape Breton Subbasins

Vitrinite Reflectance Data: Sydney Basin(Data from Mukhopadhyay, 2000)Total Fina Contract (permission from Total Inc. 2004)

Well Name Depth (m) % Ro Basin Location

N. Sydney F-24 542.5 0.68 SydneyN. Sydney F-24 804.7 0.71 SydneyN. Sydney F-24 969 0.81 SydneyN. Sydney F-24 1109.2 1.04 SydneyN. Sydney F-24 1277.1 1.02 SydneyN. Sydney F-24 1405.1 0.95 SydneyN. Sydney F-24 1508.8 0.99 SydneyN. Sydney F-24 1594.1 0.96 SydneyN. Sydney F-24 1639.8 0.94 SydneyN. Sydney F-24 1652 1.03 SydneyN. Sydney F-24 1694.7 0.94 Sydney

N. Sydney P-05 393.2 0.55 SydneyN. Sydney P-05 646.2 0.64 SydneyN. Sydney P-05 816.9 0.67 SydneyN. Sydney P-05 972.3 0.97 SydneyN. Sydney P-05 1045.5 0.94 SydneyN. Sydney P-05 1115.6 0.96 SydneyN. Sydney P-05 1332 0.95 SydneyN. Sydney P-05 1374.6 0.92 SydneyN. Sydney P-05 1475.2 0.92 SydneyN. Sydney P-05 1554.5 0.9 SydneyN. Sydney P-05 1655.1 1.01 Sydney

Kempthead-84-1 35.7 0.46 SydneyKempthead-84-1 112.5 0.54 SydneyKempthead-84-1 177 0.76 SydneyKempthead-84-1 362 0.71 SydneyKempthead-84-1 406 0.72 SydneyKempthead-84-1 495 0.76 Sydney

WR-84-1 86.1 0.45 SydneyWR-84-1 112.5 0.54 SydneyWR-84-1 238.7 0.56 SydneyWR-84-1 355 0.61 SydneyWR-84-1 378.5 0.69 SydneyWR-84-1 393.5 0.77 SydneyWR-84-1 550.5 0.94 SydneyWR-84-1 606.5 0.99 Sydney

McIvor Pt #R-1 78.85 0.54 Central CBMcIvor Pt #R-1 149.7 0.52 Central CBMcIvor Pt #R-1 173 0.54 Central CBMcIvor Pt #R-1 645.5 0.62 Central CBMcIvor Pt #R-1 898.1 0.73 Central CB

From: Global Geoenergy Research Ltd. Figure 4b October 26, 2004

For: NSDOE Vitrinite Reflectance Data(from Mukhopadhyay, 2000)

(with permission from Total Inc. 2004)

Sydney Basin andCentral Cape Breton Subbasins

Cerro Mining #71-3 108.5 0.49 Central CBCerro Mining #71-3 125.4 0.51 Central CBCerro Mining #71-3 203.9 0.69 Central CB

NSDME #1 (6609) 23.5 0.6 SydneyNSDME #1 (6610) 42.7 0.73 SydneyNSDME #1 (6610) 76.4 1.18 Sydney

NC-87-1 42.7 0.5 SydneyNC-87-1 132.6 0.6 SydneyNC-87-1 191.3 0.61 SydneyNC-87-1 282.5 0.69 SydneyNC-87-1 380.4 0.65 SydneyNC-87-1 489.8 0.83 SydneyNC-87-1 585.5 0.8 Sydney

Glen Morrison-5-7 40.8 0.54 SydneyGlen Morrison-5-7 73.5 0.68 SydneyGlen Morrison-5-7 90.5 0.7 Sydney


For: NSDOE Bitumen Extraction and Liquid Chromatography data

Current Contract data

Bitumen Extraction and Liquid Chromatography DataCurrent Contract 2004Well Depth Extraction Extract/TOC Saturates Aromatics Resins Asphaltenes Pr/Ph Pr/nC17 Ph/nC18

(ppm) (%) (%) (%) (%)ATG-34-77 357.2 ft 1976 79 57.9 18.7 15.9 2.3 0.19 2.04 7.2Malagawatch M-3 1104.4m 3618 6.4 31.4 33.1 17.4 4.1 2.1 0.34 0.2Loch Lomond -04 196.48m 2481 6.8 17 55.6 12.7 3.5 1.7 3.3 2.71Lake Ainslie -88-1 75 ft 12395 63.8 49.5 26.6 14.8 0.1 Biodegraded Oil

Data From: Global Geoenergy Research Ltd. Table 5a (i) October 26, 2004

For: NSDOE Bitumen Extraction and Liquid Chromatography Data

Selected Samples(from Mukhopadhyay, 2000)

(permission from Total Inc. 2004)

Bitumen Extraction and Liquid Chromatography Data

From Mukhopadhyay (2000) (permission from Total Inc. 2004)Well Depth Extraction Extract/TOC Saturates Aromatics Resins Asphaltenes Pr/Ph Pr/nC17 Ph/nC18

(ppm) (%) (%) (%) (%)ATG-17-77 218 ft. 4214 2.6 33.6 13.83 50.43 2.13 0.4 1.23 2.33McIver Pt #1 149.7 ft. 1047 0.12 21.6 18 53.2 7.2 1.1 0.49 0.64McIver Pt #1 896 ft. 768 0.2 33.1 19.3 34.3 13.4 1.2 0.29 0.28Malagawatch M-9, Crude Oil unknown 77.4 13.3 8.9 0.5 0.5 0.67 1.4

From: Global Geoenergy Research Ltd. Table 5a (ii) October 26, 2004

For: NSDOE Gas Chromatography Data Current Contract(selected samples)

Table 5b. Gas Chromatography data: current contractWell Name : LL-04 Samp_Name: 196.48 m (Sample Number 68; Table 2)) Compound Name Meas. R Height Area --------------------------------------- i-C4 0.000 0.000 0.000 n-C4 0.000 0.000 0.000 i-C5 0.000 0.000 0.000 n-C5 0.000 0.000 0.000 22-DMB 0.000 0.000 0.000 I-Std. 0.000 0.000 0.000 n-C6 0.000 0.000 0.000 22-DMP 0.000 0.000 0.000 223-TMB 0.000 0.000 0.000 Bz 0.000 0.000 0.000 2-MH 0.000 0.000 0.000 23-DMP 0.000 0.000 0.000 c-13-DMCP 0.000 0.000 0.000 t-13-DMCP 0.000 0.000 0.000 3-EP 0.000 0.000 0.000 t-12-DMCP 0.000 0.000 0.000 MCH 0.000 0.000 0.000 ECP 0.000 0.000 0.000 Tol 0.000 0.000 0.000 n-C8 0.000 0.000 0.000 n-C9 0.000 0.000 0.000 n-C10 0.000 0.000 0.000 n-C11 34.357 1.256 2.085 n-C12 36.349 93.749 148.275 i-C13 36.700 74.250 214.084 i-C14 37.774 243.039 433.579 n-C13 38.204 223.822 395.211 i-C15 39.591 325.302 566.873 n-C14 39.916 266.606 473.432 i-C16 40.982 461.214 843.874 n-C15 41.516 298.402 574.622 n-C16 43.025 257.458 494.063 i-C18 43.794 442.130 945.765 n-C17 44.457 274.548 478.612 Pr 44.624 846.897 1.593e3 n-C18 45.810 217.959 340.313 Phy 46.021 484.250 922.897 n-C19 47.101 274.130 662.897 n-C20 48.329 202.668 376.426 n-C21 49.505 194.356 319.124 n-C22 50.632 241.288 381.934 n-C23 51.710 246.733 410.982

From: Global Geoenergy Research Ltd. Table 5b October 26, 2004


Well Name : LL-04 Samp_Name: 196.48 m (Sample Number 68) (continued from page 1) Compound Name Meas. R Height Area n-C24 52.745 203.306 338.874 n-C25 53.770 219.800 409.664 n-C26 54.883 135.627 279.466 n-C27 56.127 113.497 270.534 n-C28 57.537 71.339 191.575 n-C29 59.145 54.751 220.642 n-C30 60.992 29.969 124.560 n-C31 63.111 25.717 150.662 n-C32 65.564 9.660 53.377 n-C41 0.000 0.000 0.000 n-C42 0.000 0.000 0.000 n-C43 0.000 0.000 0.000 n-C44 0.000 0.000 0.000 n-C45 0.000 0.000 0.000 --------------------------------------- Well Name: Malagawatch M-3 Sample Depth: 1104.4 m (Sample Number 84; Table 2) Compound Name Meas. R Height Area --------------------------------------- i-C4 0.000 0.000 0.000 n-C4 0.000 0.000 0.000 i-C5 0.000 0.000 0.000 n-C5 0.000 0.000 0.000 22-DMB 0.000 0.000 0.000 CP 0.000 0.000 0.000 23-DMB 0.000 0.000 0.000 2-MP 0.000 0.000 0.000 3-MP 0.000 0.000 0.000 I-Std. 0.000 0.000 0.000 n-C6 0.000 0.000 0.000 22-DMP 0.000 0.000 0.000 MCP 0.000 0.000 0.000 24-DMP 0.000 0.000 0.000 223-TMB 0.000 0.000 0.000 Bz 0.000 0.000 0.000 33-DMP 0.000 0.000 0.000 CH 0.000 0.000 0.000 2-MH 0.000 0.000 0.000 23-DMP 0.000 0.000 0.000 11-DMCP 0.000 0.000 0.000 3-MH 0.000 0.000 0.000 c-13-DMCP 0.000 0.000 0.000 t-13-DMCP 0.000 0.000 0.000 3-EP 0.000 0.000 0.000 t-12-DMCP 0.000 0.000 0.000



Well Name: Malagawatch M-3 Sample Depth: 1104.4 m (Sample Number 84; Table 2) (continued from page 2) Compound Name Meas. R Height Area n-C7 0.000 0.000 0.000 MCH 0.000 0.000 0.000 ECP 0.000 0.000 0.000 Tol 0.000 0.000 0.000 n-C8 0.000 0.000 0.000 n-C9 0.000 0.000 0.000 n-C10 31.928 1.161 2.308 n-C11 34.304 106.294 163.361 n-C12 36.358 482.582 735.115 i-C13 36.659 83.023 133.866 i-C14 37.772 147.147 227.207 n-C13 38.212 739.302 1.243e3 i-C15 39.584 143.672 310.452 n-C14 39.925 844.689 1.446e3 i-C16 40.971 219.341 506.613 n-C15 41.525 830.884 1.406e3 n-C16 43.031 750.974 1.272e3 i-C18 43.782 150.530 280.565 n-C17 44.459 678.999 1.051e3 Pr 44.602 207.265 340.468 n-C18 45.812 517.831 799.808 Phy 46.001 96.539 159.402 n-C19 47.099 441.132 732.449 n-C20 48.327 366.066 588.041 n-C21 49.502 308.084 492.088 n-C22 50.626 266.595 428.045 n-C23 51.704 224.624 368.592 n-C24 52.740 192.622 304.346 n-C25 53.761 143.053 271.842 n-C26 54.873 103.251 217.401 n-C27 56.115 67.817 148.147 n-C28 57.521 43.039 110.010 n-C29 59.128 31.201 97.182 n-C30 60.976 17.698 66.062 n-C31 63.100 11.523 52.188 n-C32 65.552 7.262 35.530 n-C33 68.362 4.239 30.703 n-C34 71.544 2.870 21.935 n-C35 75.143 1.733 14.053 n-C36 79.157 1.299 11.381 n-C37 0.000 0.000 0.000 n-C38 0.000 0.000 0.000 n-C39 0.000 0.000 0.000 n-C40 0.000 0.000 0.000 n-C41 0.000 0.000 0.000 n-C42 0.000 0.000 0.000



Well Name: Malagawatch M-3 Sample Depth: 1104.4 m (Sample Number 84; Table 2) (continued from page 3) Compound Name Meas. R Height Area n-C43 0.000 0.000 0.000 n-C44 0.000 0.000 0.000 n-C45 0.000 0.000 0.000 ---------------------------------------

Well Name: ATG-34-77 Sample Depth: 357.2-357.5 ft. (108.9-109m) (Sample Number 71; Table 2) Compound Name Meas. R Height Area --------------------------------------- i-C4 0.000 0.000 0.000 n-C4 0.000 0.000 0.000 i-C5 0.000 0.000 0.000 n-C5 0.000 0.000 0.000 22-DMB 0.000 0.000 0.000 CP 0.000 0.000 0.000 23-DMB 0.000 0.000 0.000 2-MP 0.000 0.000 0.000 3-MP 0.000 0.000 0.000 I-Std. 0.000 0.000 0.000 n-C6 0.000 0.000 0.000 22-DMP 0.000 0.000 0.000 MCP 0.000 0.000 0.000 24-DMP 0.000 0.000 0.000 223-TMB 0.000 0.000 0.000 Bz 0.000 0.000 0.000 33-DMP 0.000 0.000 0.000 CH 0.000 0.000 0.000 2-MH 0.000 0.000 0.000 23-DMP 0.000 0.000 0.000 11-DMCP 0.000 0.000 0.000 3-MH 0.000 0.000 0.000 c-13-DMCP 0.000 0.000 0.000 t-13-DMCP 0.000 0.000 0.000 3-EP 0.000 0.000 0.000 t-12-DMCP 0.000 0.000 0.000 n-C7 0.000 0.000 0.000 MCH 0.000 0.000 0.000 ECP 0.000 0.000 0.000 Tol 0.000 0.000 0.000 n-C8 0.000 0.000 0.000 n-C9 0.000 0.000 0.000 n-C10 0.000 0.000 0.000 n-C11 34.303 2.357 3.918 n-C12 36.347 8.964 13.553 i-C13 36.655 3.302 5.340



Well Name: ATG-34-77 Sample Depth: 357.2-357.5 ft. (108.9-109m) (Sample Number 71; Table 2) Compound Name Meas. R Height Area i-C14 37.766 7.376 11.567 n-C13 38.194 17.696 27.024 i-C15 39.576 9.327 14.150 n-C14 39.903 24.915 39.295 i-C16 40.963 15.579 30.689 n-C15 41.502 28.857 47.785 n-C16 43.011 26.993 42.180 i-C18 43.773 25.192 48.378 n-C17 44.439 35.168 56.317 Pr 44.593 64.069 115.342 n-C18 45.795 38.858 83.439 Phy 46.004 319.543 601.518 n-C19 47.078 95.856 265.114 n-C20 48.319 89.361 189.542 n-C21 49.497 113.923 207.199 n-C22 50.625 141.683 229.666 n-C23 51.705 178.240 277.326 n-C24 52.743 197.599 312.324 n-C25 53.768 219.478 409.618 n-C26 54.884 194.530 399.853 n-C27 56.132 188.061 534.710 n-C28 57.541 152.649 409.253 n-C29 59.156 127.676 427.147 n-C30 61.005 87.250 322.479 n-C31 63.133 71.852 364.755 n-C32 65.588 39.446 216.884 n-C33 68.385 29.506 213.520 n-C34 71.585 19.314 136.560 n-C35 75.180 12.247 98.520 n-C36 79.216 9.605 91.451 n-C37 83.677 7.707 82.032 n-C38 88.539 5.739 66.883 n-C39 93.779 3.386 38.359 n-C40 99.429 2.956 35.227 n-C41 105.427 1.783 18.423 n-C42 112.321 1.237 14.960 n-C43 0.000 0.000 0.000 n-C44 0.000 0.000 0.000 n-C45 0.000 0.000 0.000 ---------------------------------------


HGS ID: 04-2477-84574Type: RockWell: Lake Ainsle 88-1Depth: 75 ft

Saturate Biomarker Integration Results(Terpanes)

Ion Peak Compound R.Time Peak ppm Peak ppmLabel Name (min.) Area (A.) Height (Ht.)

125 BCRT b-carotane191 C19t C19 tricyclic diterpane 40.72 8212 18.8 2531 21.8191 C20t C20 tricyclic diterpane 43.00 66690 152.4 21600 185.8191 C21t C21 tricyclic diterpane 45.34 112000 255.9 39710 341.7191 C22t C22 tricyclic terpane 47.47 20990 48.0 7081 60.9191 C23t C23 tricyclic terpane 49.89 142800 326.3 49170 423.0191 C24t C24 tricyclic terpane 51.22 87710 200.4 30400 261.6191 C25tS C25 tricyclic terpane (S) 53.78 31910 72.9 11370 97.8191 C25tR C25 tricyclic terpane (R) 53.86 34330 78.4 11840 101.9191 C24T C24 tetracyclic terpane (TET) 55.39 23580 53.9 7881 67.8191 C26tS C26 tricyclic terpane (S) 55.66 53960 123.3 17850 153.6191 C26tR C26 tricyclic terpane (R) 55.83 52840 120.7 18010 155.0191 C28tS C28 extended tricyclic terpane (S) 59.83 51270 117.2 16100 138.5191 C28tR C28 extended tricyclic terpane (R) 60.13 50030 114.3 15680 134.9191 C29tS C29 extended tricyclic terpane (S) 61.04 42510 97.1 11430 98.3191 C29tR C29 extended tricyclic terpane (R) 61.39 40940 93.6 12070 103.8191 C30tR C30 extended tricyclic terpane (S) 63.28 49730 113.6 11670 100.4191 C30tR C30 extended tricyclic terpane (R) 63.66 44080 100.7 9992 86.0191 Ts Ts 18a(H)-trisnorhopane 62.20 50070 114.4 13780 118.6191 Tm Tm 17a(H)-trisnorhopane 62.95 80320 183.5 24180 208.0191 C28BNH C28 17a18a21b(H)-bisnorhopane 64.95 54800 125.2 12050 103.7191 Nor25H C29 Nor-25-hopane 65.35 42960 98.2 12900 111.0191 C29H C29 Tm 17a(H)21b(H)-norhopane 65.62 282700 646.0 84350 725.7191 C29Ts C29 Ts 18a(H)-norneohopane 65.72 61000 139.4 16820 144.7191 C30DiaH C30 17a(H)-diahopane 66.03 41430 94.7 8108 69.8191 Normor C29 normoretane 66.48 51210 117.0 11390 98.0191 a-Ole a-oleanane 66.93 4467 10.2 1185 10.2191 b-Ole b-oleanane 66.98 4806 11.0 1061 9.1191 C30H C30 17a(H)-hopane 67.22 513900 1174.3 162600 1399.0191 Mor C30 moretane 67.88 78860 180.2 25590 220.2191 C31HS C31 22S 17a(H) homohopane 69.02 120900 276.3 36630 315.2191 C31HR C31 22R 17a(H) homohopane 69.22 90550 206.9 26350 226.7191 Gam gammacerane 69.42 102400 234.0 31150 268.0191 C32HS C32 22S 17a(H) bishomohopane 70.42 72630 166.0 21410 184.2191 C32HR C32 22R 17a(H) bishomohopane 70.72 54270 124.0 15550 133.8191 C33HS C33 22S 17a(H) trishomohopane 72.13 48760 111.4 11660 100.3191 C33HR C33 22R 17a(H) trishomohopane 72.59 32040 73.2 7203 62.0191 C34HS C34 22S 17a(H) extended hopane 74.14 31510 72.0 6152 52.9191 C34HR C34 22R 17a(H) extended hopane 74.79 25060 57.3 3976 34.2191 C35HS C35 22S 17a(H) extended hopane 76.44 25760 58.9 3822 32.9191 C35HR C35 22R 17a(H) extended hopane 77.26 18090 41.3 3162 27.2

Table 6a

HGS ID: 04-2477-84574Type: RockWell: Lake Ainsle 88-1Depth: 75 ft

Saturate Biomarker Integration Results(Steranes)


217 S21 C21 sterane 47.71 9843 22.5 2865 24.6217 S22 C22 sterane 50.43 6330 14.5 1182 10.2217 27DbaS C27 ba 20S diacholestane 57.69 5593 12.8 1727 14.9217 27DbaR C27 ba 20R diacholestane 58.44 4137 9.5 1145 9.9217 28DbaSA C28 ba 20S diasterane a 59.79 4402 10.1 1029 8.9217 28DbaSB C28 ba 20S diasterane b 59.88 2910 6.6 907 7.8217 28DbaRA C28 ba 20R diasterane a 60.41 13570 31.0 3010 25.9217 28DbaRB C28 ba 20R diasterane b 60.47 10410 23.8 3106 26.7217 27aaS C27 aa 20S cholestane 60.96 21230 48.5 5035 43.3217 27bbR C27 bb 20R cholestane 61.12 23190 53.0 6051 52.1217 27bbS C27 bb 20S cholestane 61.28 20350 46.5 5777 49.7217 27aaR C27 aa 20R cholestane 61.76 29760 68.0 8310 71.5217 28aaS C28 aa 20S ergostane 62.87 16640 38.0 5627 48.4217 28bbR C28 bb 20R ergostane 63.14 42060 96.1 8588 73.9217 28bbS C28 bb 20S ergostane 63.29 57930 132.4 16590 142.7217 28aaR C28 aa 20R ergostane 63.89 55750 127.4 10740 92.4217 29aaS C29 aa 20S stigmastane 64.45 94060 214.9 20870 179.6217 29bbR C29 bb 20R stigmastane 64.77 66290 151.5 16840 144.9217 29bbS C29 bb 20S stigmastane 64.88 70770 161.7 18730 161.1217 29aaR C29 aa 20R stigmastane 65.60 116900 267.1 32180 276.9218 27bbR C27 bb 20R cholestane 61.13 24520 56.0 7746 66.6218 27bbS C27 bb 20S cholestane 61.28 23930 54.7 7484 64.4218 28bbR C28 bb 20R ergostane 63.14 56310 128.7 13190 113.5218 28bbS C28 bb 20S ergostane 63.29 74450 170.1 21200 182.4218 29bbR C29 bb 20R stigmastane 64.77 99600 227.6 28430 244.6218 29bbS C29 bb 20S stigmastane 64.88 101700 232.4 30690 264.0259 27DbaS C27 ba 20S diacholestane 57.69 3048 7.0 1048 9.0259 27DbaR C27 ba 20R diacholestane 58.45 3599 8.2 725 6.2259 28DbaSA C28 ba 20S diaergostane a 59.84 920 2.1 281 2.4259 28DbaSB C28 ba 20S diaergostane b 59.89 777 1.8 278 2.4259 28DbaRA C28 ba 20R diaergostane a 60.40 2633 6.0 775 6.7259 28DbaRB C28 ba 20R diaergostane b 60.47 4146 9.5 725 6.2259 29DbaS C29 ba 20S diastigmastane 61.13 14180 32.4 2406 20.7259 29DbaR C29 ba 20R diastigmastane 62.00 9539 21.8 1281 11.0259 30TP1 C30 Terpane 66.46 15110 34.5 4570 39.3259 30TP2 C30 Terpane 66.54 14880 34.0 4516 38.9

217 b-Cholane 5b-cholane (inter. STD) 54.83 12820 29.3 3405 29.3218 b-Cholane 5b-cholane (inter. STD) 54.83 5464 29.3 1492 29.3

Table 6a

Saturate Biomarker Interpretive Ratios

HGS ID: 04-2477-84574 Interpretive By ByType: Rock Ratios Area HeightWell: Lake Ainsle 88-1Depth: 75 ft Terpanes (m/z 191)

C19t/C23t 0.06 0.05C22t/C21t 0.19 0.18C22t/C24t 0.24 0.23C24t/C23t 0.61 0.62C26t/C25t 1.61 1.55

C24Tet/C23t 0.17 0.16C24Tet/C26t 0.22 0.22C23t/C30H 0.28 0.30

C24Tet/C30H 0.05 0.05C28BNH/C30H 0.11 0.0725-Nor/C30H 0.08 0.08C29H/C30H 0.55 0.52

C30DiaH/C30H 0.08 0.05Ole/C30H 0.02 0.01

C31HR/C30H 0.18 0.16Gam/C30H 0.20 0.19

Gam/C31HR 1.13 1.18C35HS/C34HS 0.82 0.62

C35 Homohopane Index 0.08 0.05Ts/(Ts+Tm) 0.38 0.36

C29Ts/(C29Ts+C29H) 0.18 0.17Mor/C30H 0.15 0.16

C32 S/(S+R) 0.57 0.58

Steranes (m/z 217)C27 ααα 20R 14.7% 16.2%C28 ααα 20R 27.5% 21.0%C29 ααα 20R 57.8% 62.8%

C27 Dia/(Dia+Reg) 0.16 0.18(C21+C22)/(C27+C28+C29) 0.03 0.03

C29 αββ /(ααα+αββ ) 0.39 0.40C29 ααα 20S/20R 0.80 0.65

C29 ααα 20S/(S+R) 0.45 0.39

αββ− Steranes (m/z 218)C27 αββ 20(R+S) 12.7% 14.0%C28 αββ 20(R+S) 34.4% 31.6%C29 αββ 20(R+S) 52.9% 54.4%

C29/C27 αββ Sterane Ratio 4.15 3.88

Tricyclic/Pentacyclic Terpanes 0.48 0.54Steranes/Terpanes 0.24 0.20Tricyclic Terpanes 26.3% 29.3%

Pentacyclic Terpanes 54.4% 53.8%Steranes 19.3% 16.9%

Table 6a

HGS ID: 04-2477-84539Type: RockWell: ATG-34-77Depth: 357.2-357.5




Table 6a


HGS ID: 04-2477-84539 Interpretive By ByType: Rock Ratios Area HeightWell: ATG-34-77Depth: 357.2-357.5 Terpanes (m/z 191)




C30DiaH/C30H 0.08 0.06Ole/C30H 0.02 0.02

C31HR/C30H 0.20 0.16Gam/C30H 0.29 0.26

Gam/C31HR 1.49 1.60C35HS/C34HS 0.55 0.59


C29Ts/(C29Ts+C29H) 0.20 0.17Mor/C30H 0.11 0.11

C32 S/(S+R) 0.58 0.57




C29 ααα 20S/(S+R) 0.51 0.45





Table 6a


HGS ID: 04-2477-84539 Interpretive By ByType: Rock Ratios Area HeightWell: ATG-34-77Depth: 357.2-357.5 Terpanes (m/z 191)




C30DiaH/C30H 0.08 0.06Ole/C30H 0.02 0.02

C31HR/C30H 0.20 0.16Gam/C30H 0.29 0.26

Gam/C31HR 1.49 1.60C35HS/C34HS 0.55 0.59


C29Ts/(C29Ts+C29H) 0.20 0.17Mor/C30H 0.11 0.11

C32 S/(S+R) 0.58 0.57




C29 ααα 20S/(S+R) 0.51 0.45





Table 6a

HGS ID: 04-2477-84559Type: RockWell: M-3Depth: 1104.4m




Table 6a

HGS ID: 04-2477-84559Type: RockWell: M-3Depth: 1104.4m





Table 6a


HGS ID: 04-2477-84559 Interpretive By ByType: Rock Ratios Area HeightWell: M-3Depth: 1104.4m Terpanes (m/z 191)




C30DiaH/C30H 0.80 0.82Ole/C30H 0.10 0.13

C31HR/C30H 0.44 0.26Gam/C30H 0.19 0.19

Gam/C31HR 0.43 0.72C35HS/C34HS 0.00 0.00


C29Ts/(C29Ts+C29H) 0.43 0.40Mor/C30H 0.19 0.13

C32 S/(S+R) 0.53 0.60




C29 ααα 20S/(S+R) 0.48 0.45





Table 6a

HGS ID: 04-2477-84563Type: RockWell: LL-04Depth: 196.48m




Figure 6a

HGS ID: 04-2477-84563Type: RockWell: LL-04Depth: 196.48m





Table 6a


HGS ID: 04-2477-84563 Interpretive By ByType: Rock Ratios Area HeightWell: LL-04Depth: 196.48m Terpanes (m/z 191)




C30DiaH/C30H 0.17 0.12Ole/C30H 0.01 0.02

C31HR/C30H 0.31 0.33Gam/C30H 0.55 0.57

Gam/C31HR 1.77 1.74C35HS/C34HS 0.66 0.55


C29Ts/(C29Ts+C29H) 0.14 0.13Mor/C30H 0.18 0.20

C32 S/(S+R) 0.55 0.59




C29 ααα 20S/(S+R) 0.47 0.46





Table 6a

For: NSDOE Sterane and Triterpane data (Permission from Total Inc., 2004)

TRITERPANE REPORT (m/z 191)Sample No. GG000061 Other ID: ATG-17-77; 218Ft.

No. ID Triterpane Name Ret Time Area Area% PPM

1 A C19 Tricyclic Terpane 19.087 1714 0.27 192 B C20 Tricyclic Terpane 21.892 14534 2.30 1623 C C21 Tricyclic Terpane 25.221 21772 3.44 2424 D C22 Tricyclic Terpane 28.584 5296 0.84 595 E C23 Tricyclic Terpane 32.814 30528 4.83 3406 F C24 Tricyclic Terpane 35.220 18319 2.90 2047 G C25 Tricyclic Terpane (22R) 40.276 7980 1.26 898 G C25 Tricyclic Terpane (22S) 40.398 8887 1.41 999 H C24 Tetracyclic Terpane 43.519 5893 0.93 66

10 I C26 Tricyclic Terpane (22R) 44.164 10817 1.71 12011 I C26 Tricyclic Terpane (22S) 44.495 10659 1.69 11912 J C28 Tricyclic Terpane (22R) 53.074 10666 1.69 11913 J C28 Tricyclic Terpane (22S) 53.684 11709 1.85 13014 K C29 Tricyclic Terpane (22R) 55.636 9097 1.44 10115 K C29 Tricyclic Terpane (22S) 56.386 9181 1.45 10216 L C27 18aH-Trisnorhopane (Ts) 57.764 6111 0.97 6817 M C27 17aH-Trisnorhopane (Tm) 59.420 19326 3.06 21518 N C30 Tricyclic Terpane (22R) 60.588 8215 1.30 9119 N C30 Tricyclic Terpane (22S) 61.407 8744 1.38 9720 O C28 17aH,18aH,21bH-28,30-Bisnorhopane 0 0.00 <121 P C31 Tricyclic Terpane (22R) 64.302 7367 1.16 8222 Q C29 17aH,21bH 25-Norhopane 63.988 2087 0.33 2323 P C31 Tricyclic Terpane (22S) 65.208 7367 1.16 8224 R C29 17aH,21bH-Norhopane 65.208 54053 8.55 60225 S C29 18aH-Norneohopane (29Ts 65.452 11015 1.74 12326 T C30 17aH Diahopane 66.219 2972 0.47 3327 U C29 17bH,21aH-Normoretane 67.196 5652 0.89 6328 V C30 18aH+18bH-Oleanane 68.259 2427 0.38 2729 W C30 17aH,21bH-Hopane 68.678 108525 17.16 120930 X C30 30-Nor-29-homo-17aH-hop 68.887 4757 0.75 5331 Y C30 17bH,21aH-Moretane 70.230 13696 2.17 15332 Z C33 Tricyclic Terpane (22R) 72.304 8597 1.36 9633 Z C33 Tricyclic Terpane (22S) 73.316 2128 0.34 2434 a C31 17aH,21bH-Homohopane ( 72.705 25393 4.01 28335 b C31 17aH,21bH-Homohopane ( 73.211 26148 4.13 29136 c C30 Gammacerane 73.647 22232 3.52 24837 d C34 Tricyclic Terpane (22R) 74.588 13191 2.09 147

From: Global Geoenergy Research Ltd.Table 6b

1 August 12, 2004


TRITERPANE REPORT (m/z 191)Sample No. GG000061 Other ID: ATG-17-77; 218Ft.


38 d C34 Tricyclic Terpane (22S) 75.512 7950 1.26 8939 e C32 17aH,21bH-Bishomohopan 75.931 18637 2.95 20840 f C32 17aH,21bH-Bishomohopan 76.611 12648 2.00 14141 g C35 Tricyclic Terpane (22R) 78.999 8918 1.41 9942 g C35 Tricyclic Terpane (22S) 79.941 8789 1.39 9843 h C33 17aH,21bH-Trishomohopa 79.627 9513 1.50 10644 i C33 17aH,21bH-Trishomohopa 80.586 7450 1.18 8345 j C34 17aH,21bH-Tetrahomohop 83.480 7826 1.24 8746 k C34 17aH,21bH-Tetrahomohop 84.648 4769 0.75 5347 l C35 17aH,21bH-Pentahomohop 87.211 5346 0.85 6048 m C35 17aH,21bH-Pentahomohop 88.519 3587 0.57 40


2 August 12, 2004


STERANE REPORT (m/z 217)Sample No. GG000061 Other ID: ATG-17-77; 218Ft.

No. ID Sterane Name Ret Time Area Area% PPM

1 A C21 diasterane 26.09 592 0.12 72 B C21 abb sterane 29.16 5039 1.04 563 C C22 diasterane 29.39 1059 0.22 124 D C22 abb sterane 33.86 2631 0.54 295 E C27 ba diasterane (20S) 48.58 1543 0.32 176 F C27 ba diasterane (20R) 50.21 5805 1.20 657 G C27 ab diasterane (20S) 0 0.00 <18 H C27 ab diasterane (20R) 0 0.00 <19 I C28 ba diasterane (20S) 52.38 8500 1.76 95

10 J C28 ba diasterane (20R) 54.14 14760 3.05 16411 K C28 ab diasterane (20S) 54.99 3711 0.77 4112 L C27 aaa sterane (20S) 55.24 12245 2.53 13613 M C27 abb ster-(20R)+C29 ba dia- 55.74 15938 3.30 17814 N C27 abb sterane (20S) 56.14 18713 3.87 20815 O C28 ab diasterane (20R) 0 0.00 <116 P C27 aaa sterane (20R) 57.03 11604 2.40 12917 Q C29 ba diasterane (20R) 57.68 31537 6.53 35118 R C29 ab diasterane (20S) 58.39 3386 0.70 3819 S C28 aaa sterane (20S) 59.35 15304 3.17 17020 T C29 ab diasterane (20R) 60.08 35193 7.28 39221 U C28 abb sterane (20R) 0 0.00 <122 V C28 abb sterane (20S) 60.47 54534 11.28 60723 W C28 aaa sterane (20R) 61.63 21041 4.35 23424 X C29 aaa sterane (20S) 62.86 44672 9.24 49825 Y C29 abb sterane (20R) 63.69 67219 13.91 74926 Z C29 abb sterane (20S) 64.01 54608 11.30 60827 a C29 aaa sterane (20R) 65.40 53628 11.10 59728 b C30 aaa sterane (20S) 0 0.00 <129 c C30 abb sterane (20R) 0 0.00 <130 d C30 abb sterane (20S) 0 0.00 <131 e C30 aaa sterane (20R) 0 0.00 <1


3 August 12, 2004


TRITERPANE REPORT (m/z 191)Sample No. GG000068 Other ID: McIvor Pt #R-1 - 149.7 Ft.



10 I C26 Tricyclic Terpane (22R) 44.095 1206 0.29 1611 I C26 Tricyclic Terpane (22S) 44.478 1171 0.28 1512 J C28 Tricyclic Terpane (22R) 53.039 722 0.17 913 J C28 Tricyclic Terpane (22S) 53.597 1317 0.31 1714 K C29 Tricyclic Terpane (22R) 0 0.00 <115 K C29 Tricyclic Terpane (22S) 0 0.00 <116 L C27 18aH-Trisnorhopane (Ts) 57.746 11245 2.67 14517 M C27 17aH-Trisnorhopane (Tm) 59.385 21618 5.14 27918 N C30 Tricyclic Terpane (22R) 0 0.00 <119 N C30 Tricyclic Terpane (22S) 0 0.00 <120 O C28 17aH,18aH,21bH-28,30-Bi 63.517 1172 0.28 1521 P C31 Tricyclic Terpane (22R) 0 0.00 <122 Q C29 17aH,21bH 25-Norhopane 0 0.00 <123 P C31 Tricyclic Terpane (22S) 0 0.00 <124 R C29 17aH,21bH-Norhopane 65.156 31624 7.52 40825 S C29 18aH-Norneohopane (29Ts 65.418 19262 4.58 24926 T C30 17aH Diahopane 66.202 11210 2.66 14527 U C29 17bH,21aH-Normoretane 67.144 4410 1.05 5728 V C30 18aH+18bH-Oleanane 68.207 899 0.21 1229 W C30 17aH,21bH-Hopane 68.626 72997 17.35 94230 X C30 30-Nor-29-homo-17aH-hop 68.817 1223 0.29 1631 Y C30 17bH,21aH-Moretane 70.195 8769 2.08 11332 Z C33 Tricyclic Terpane (22R) 0 0.00 <133 Z C33 Tricyclic Terpane (22S) 0 0.00 <134 a C31 17aH,21bH-Homohopane ( 72.688 44221 10.51 57135 b C31 17aH,21bH-Homohopane ( 73.194 30444 7.24 39336 c C30 Gammacerane 73.630 5130 1.22 6637 d C34 Tricyclic Terpane (22R) 0 0.00 <138 d C34 Tricyclic Terpane (22S) 0 0.00 <1


4 August 12, 2004


TRITERPANE REPORT (m/z 191)Sample No. GG000068 Other ID: McIvor Pt #R-1 - 149.7 Ft.


39 e C32 17aH,21bH-Bishomohopan 75.914 34745 8.26 44840 f C32 17aH,21bH-Bishomohopan 76.593 23185 5.51 29941 g C35 Tricyclic Terpane (22R) 0 0.00 <142 g C35 Tricyclic Terpane (22S) 0 0.00 <143 h C33 17aH,21bH-Trishomohopa 79.610 16857 4.01 21744 i C33 17aH,21bH-Trishomohopa 80.569 11582 2.75 14945 j C34 17aH,21bH-Tetrahomohop 83.480 13173 3.13 17046 k C34 17aH,21bH-Tetrahomohop 84.614 8974 2.13 11647 l C35 17aH,21bH-Pentahomohop 87.194 4933 1.17 6448 m C35 17aH,21bH-Pentahomohop 88.484 3749 0.89 48


5 August 12, 2004


STERANE REPORT (m/z 217)Sample No. GG000068 Other ID: McIvor Pt #R-1 - 149.7 Ft. Sample 68


1 A C21 diasterane 26.06 1492 2.03 192 B C21 abb sterane 29.14 2181 2.97 283 C C22 diasterane 29.39 1063 1.45 144 D C22 abb sterane 33.86 823 1.12 115 E C27 ba diasterane (20S) 48.49 4223 5.74 546 F C27 ba diasterane (20R) 50.04 2751 3.74 357 G C27 ab diasterane (20S) 51.14 1659 2.26 218 H C27 ab diasterane (20R) 51.96 1325 1.80 179 I C28 ba diasterane (20S) 52.31 3119 4.24 40

10 J C28 ba diasterane (20R) 54.00 1915 2.60 2511 K C28 ab diasterane (20S) 55.08 516 0.70 712 L C27 aaa sterane (20S) 55.18 1796 2.44 2313 M C27 abb ster-(20R)+C29 ba dia- 55.81 11465 15.59 14814 N C27 abb sterane (20S) 56.11 2968 4.04 3815 O C28 ab diasterane (20R) 56.33 400 0.54 516 P C27 aaa sterane (20R) 56.89 2855 3.88 3717 Q C29 ba diasterane (20R) 57.62 7940 10.79 10218 R C29 ab diasterane (20S) 58.37 3205 4.36 4119 S C28 aaa sterane (20S) 59.37 1662 2.26 2120 T C29 ab diasterane (20R) 59.86 4112 5.59 5321 U C28 abb sterane (20R) 60.01 679 0.92 922 V C28 abb sterane (20S) 60.43 1354 1.84 1723 W C28 aaa sterane (20R) 0 0.00 <124 X C29 aaa sterane (20S) 62.82 3095 4.21 4025 Y C29 abb sterane (20R) 63.62 4185 5.69 5426 Z C29 abb sterane (20S) 63.92 3257 4.43 4227 a C29 aaa sterane (20R) 65.35 3515 4.78 4528 b C30 aaa sterane (20S) 0 0.00 <129 c C30 abb sterane (20R) 0 0.00 <130 d C30 abb sterane (20S) 0 0.00 <131 e C30 aaa sterane (20R) 0 0.00 <1


6 August 12, 2004


TRITERPANE REPORT (m/z 191)Sample No. GG000071 Other ID: McIvor Pt #R-1 - 896 Ft.



10 I C26 Tricyclic Terpane (22R) 44.148 835 0.58 911 I C26 Tricyclic Terpane (22S) 44.479 1105 0.77 1212 J C28 Tricyclic Terpane (22R) 53.039 1228 0.85 1313 J C28 Tricyclic Terpane (22S) 53.632 1176 0.82 1314 K C29 Tricyclic Terpane (22R) 55.620 767 0.53 815 K C29 Tricyclic Terpane (22S) 56.370 537 0.37 616 L C27 18aH-Trisnorhopane (Ts) 57.747 9397 6.53 10317 M C27 17aH-Trisnorhopane (Tm) 59.386 4248 2.95 4718 N C30 Tricyclic Terpane (22R) 0 0.00 <119 N C30 Tricyclic Terpane (22S) 0 0.00 <120 O C28 17aH,18aH,21bH-28,30-Bisnorhopane 0 0.00 <121 P C31 Tricyclic Terpane (22R) 0 0.00 <122 Q C29 17aH,21bH 25-Norhopane 0 0.00 <123 P C31 Tricyclic Terpane (22S) 0 0.00 <124 R C29 17aH,21bH-Norhopane 65.139 8161 5.67 9025 S C29 18aH-Norneohopane (29Ts 65.401 10622 7.38 11726 T C30 17aH Diahopane 66.185 6780 4.71 7527 U C29 17bH,21aH-Normoretane 67.162 1775 1.23 2028 V C30 18aH+18bH-Oleanane 0 0.00 <129 W C30 17aH,21bH-Hopane 68.626 20779 14.45 22830 X C30 30-Nor-29-homo-17aH-hop 68.853 1000 0.70 1131 Y C30 17bH,21aH-Moretane 70.178 2640 1.84 2932 Z C33 Tricyclic Terpane (22R) 0 0.00 <133 Z C33 Tricyclic Terpane (22S) 0 0.00 <134 a C31 17aH,21bH-Homohopane ( 72.671 9589 6.67 10535 b C31 17aH,21bH-Homohopane ( 73.177 6571 4.57 7236 c C30 Gammacerane 73.665 1266 0.88 1437 d C34 Tricyclic Terpane (22R) 0 0.00 <138 d C34 Tricyclic Terpane (22S) 0 0.00 <1


7 August 12, 2004


TRITERPANE REPORT (m/z 191)Sample No. GG000071 Other ID: McIvor Pt #R-1 - 896 Ft.


39 e C32 17aH,21bH-Bishomohopan 75.897 9401 6.54 10340 f C32 17aH,21bH-Bishomohopan 76.594 5817 4.04 6441 g C35 Tricyclic Terpane (22R) 0 0.00 <142 g C35 Tricyclic Terpane (22S) 0 0.00 <143 h C33 17aH,21bH-Trishomohopa 79.610 4815 3.35 5344 i C33 17aH,21bH-Trishomohopa 80.552 2873 2.00 3245 j C34 17aH,21bH-Tetrahomohop 83.464 4231 2.94 4646 k C34 17aH,21bH-Tetrahomohop 84.597 3260 2.27 3647 l C35 17aH,21bH-Pentahomohop 87.177 1763 1.23 1948 m C35 17aH,21bH-Pentahomohop 88.485 1201 0.83 13


8 August 12, 2004


STERANE REPORT (m/z 217)Sample No. GG000071 Other ID: McIvor Pt #R-1 - 896 Ft. Sample 71


1 A C21 diasterane 26.08 1764 2.60 192 B C21 abb sterane 29.14 2788 4.11 313 C C22 diasterane 29.39 1623 2.39 184 D C22 abb sterane 33.86 1117 1.65 125 E C27 ba diasterane (20S) 48.49 4571 6.74 506 F C27 ba diasterane (20R) 50.06 2853 4.20 317 G C27 ab diasterane (20S) 51.14 1631 2.40 188 H C27 ab diasterane (20R) 51.96 1505 2.22 179 I C28 ba diasterane (20S) 52.29 2774 4.09 30

10 J C28 ba diasterane (20R) 54.03 1682 2.48 1811 K C28 ab diasterane (20S) 55.11 600 0.88 712 L C27 aaa sterane (20S) 55.22 1383 2.04 1513 M C27 abb ster-(20R)+C29 ba dia- 55.83 9547 14.07 10514 N C27 abb sterane (20S) 56.11 2695 3.97 3015 O C28 ab diasterane (20R) 56.32 594 0.88 716 P C27 aaa sterane (20R) 57.02 1979 2.92 2217 Q C29 ba diasterane (20R) 57.63 7048 10.39 7718 R C29 ab diasterane (20S) 58.38 2528 3.73 2819 S C28 aaa sterane (20S) 59.30 358 0.53 420 T C29 ab diasterane (20R) 59.84 3243 4.78 3621 U C28 abb sterane (20R) 60.01 695 1.02 822 V C28 abb sterane (20S) 60.41 1748 2.58 1923 W C28 aaa sterane (20R) 61.64 314 0.46 324 X C29 aaa sterane (20S) 62.82 2270 3.35 2525 Y C29 abb sterane (20R) 63.62 4176 6.15 4626 Z C29 abb sterane (20S) 63.94 3466 5.11 3827 a C29 aaa sterane (20R) 65.37 2896 4.27 3228 b C30 aaa sterane (20S) 0 0.00 <129 c C30 abb sterane (20R) 0 0.00 <130 d C30 abb sterane (20S) 0 0.00 <131 e C30 aaa sterane (20R) 0 0.00 <1


9 August 12, 2004


TRITERPANE REPORT (m/z 191)Chevron-Irving CB-9, Malagawatch Oil; Central Cape Breton

Sample No. GG000084 Other ID: MALAGAWATCHNo. ID Triterpane Name Ret Time Area Area% PPM


10 I C26 Tricyclic Terpane (22R) 44.095 10432 3.39 11311 I C26 Tricyclic Terpane (22S) 44.426 10846 3.52 11712 J C28 Tricyclic Terpane (22R) 53.022 10082 3.27 10913 J C28 Tricyclic Terpane (22S) 53.632 10628 3.45 11514 K C29 Tricyclic Terpane (22R) 55.584 8526 2.77 9215 K C29 Tricyclic Terpane (22S) 56.317 8849 2.87 9516 L C27 18aH-Trisnorhopane (Ts) 57.729 3446 1.12 3717 M C27 17aH-Trisnorhopane (Tm) 59.350 2080 0.68 2218 N C30 Tricyclic Terpane (22R) 60.519 7384 2.40 8019 N C30 Tricyclic Terpane (22S) 61.338 7366 2.39 7920 O C28 17aH,18aH,21bH-28,30-Bisnorhopane 0 0.00 <121 P C31 Tricyclic Terpane (22R) 64.232 8639 2.81 9322 Q C29 17aH,21bH 25-Norhopane 63.884 626 0.20 723 P C31 Tricyclic Terpane (22S) 65.121 8639 2.81 9324 R C29 17aH,21bH-Norhopane 65.121 4289 1.39 4625 S C29 18aH-Norneohopane (29Ts 65.383 2802 0.91 3026 T C30 17aH Diahopane 66.150 2343 0.76 2527 U C29 17bH,21aH-Normoretane 67.109 1377 0.45 1528 V C30 18aH+18bH-Oleanane 68.207 977 0.32 1129 W C30 17aH,21bH-Hopane 68.591 8497 2.76 9230 X C30 30-Nor-29-homo-17aH-hop 68.853 1220 0.40 1331 Y C30 17bH,21aH-Moretane 70.143 1132 0.37 1232 Z C33 Tricyclic Terpane (22R) 72.252 9196 2.99 9933 Z C33 Tricyclic Terpane (22S) 73.159 7377 2.40 8034 a C31 17aH,21bH-Homohopane ( 72.653 2093 0.68 2335 b C31 17aH,21bH-Homohopane ( 73.107 2795 0.91 3036 c C30 Gammacerane 73.577 3798 1.23 4137 d C34 Tricyclic Terpane (22R) 74.571 8969 2.91 97


10 August 12, 2004


TRITERPANE REPORT (m/z 191)Chevron-Irving CB-9, Malagawatch Oil; Central Cape Breton

Sample No. GG000084 Other ID: MALAGAWATCHNo. ID Triterpane Name Ret Time Area Area% PPM

38 d C34 Tricyclic Terpane (22S) 75.478 8232 2.67 8939 e C32 17aH,21bH-Bishomohopan 75.861 1143 0.37 1240 f C32 17aH,21bH-Bishomohopan 76.559 948 0.31 1041 g C35 Tricyclic Terpane (22R) 78.947 7969 2.59 8642 g C35 Tricyclic Terpane (22S) 79.871 7285 2.37 7943 h C33 17aH,21bH-Trishomohopa 79.592 694 0.23 744 i C33 17aH,21bH-Trishomohopa 80.517 699 0.23 845 j C34 17aH,21bH-Tetrahomohopane (22S) 0 0.00 <146 k C34 17aH,21bH-Tetrahomohopane (22R) 0 0.00 <147 l C35 17aH,21bH-Pentahomohopane (22S) 0 0.00 <148 m C35 17aH,21bH-Pentahomohopane (22R) 0 0.00 <1


11 August 12, 2004


STERANE REPORT (m/z 217)Chevron-Irving CB-9, Malagawatch Oil; Central Cape Breton

Sample No. GG000084 Other ID: MALAGAWATCHNo. ID Sterane Name Ret Time Area Area% PPM

1 A C21 diasterane 26.06 530 0.50 62 B C21 abb sterane 29.12 3223 3.04 353 C C22 diasterane 29.35 548 0.52 64 D C22 abb sterane 33.83 1088 1.03 125 E C27 ba diasterane (20S) 48.47 318 0.30 36 F C27 ba diasterane (20R) 50.04 227 0.21 27 G C27 ab diasterane (20S) 0 0.00 <18 H C27 ab diasterane (20R) 0 0.00 <19 I C28 ba diasterane (20S) 1629 1.54 18

10 J C28 ba diasterane (20R) 54.09 3911 3.69 4211 K C28 ab diasterane (20S) 54.96 800 0.75 912 L C27 aaa sterane (20S) 55.18 2244 2.11 2413 M C27 abb ster-(20R)+C29 ba dia- 55.69 4175 3.93 4514 N C27 abb sterane (20S) 56.07 4877 4.60 5315 O C28 ab diasterane (20R) 0 0.00 <116 P C27 aaa sterane (20R) 56.98 2239 2.11 2417 Q C29 ba diasterane (20R) 57.61 8721 8.22 9418 R C29 ab diasterane (20S) 58.36 1186 1.12 1319 S C28 aaa sterane (20S) 59.26 2406 2.27 2620 T C29 ab diasterane (20R) 59.87 784 0.74 821 U C28 abb sterane (20R) 60.00 6844 6.45 7422 V C28 abb sterane (20S) 60.40 12166 11.46 13123 W C28 aaa sterane (20R) 61.57 3384 3.19 3724 X C29 aaa sterane (20S) 62.79 7307 6.89 7925 Y C29 abb sterane (20R) 63.59 15240 14.36 16426 Z C29 abb sterane (20S) 63.92 12685 11.95 13727 a C29 aaa sterane (20R) 65.31 9587 9.03 10328 b C30 aaa sterane (20S) 0 0.00 <129 c C30 abb sterane (20R) 0 0.00 <130 d C30 abb sterane (20S) 0 0.00 <131 e C30 aaa sterane (20R) 0 0.00 <1


12 August 12, 2004

For: NSDOE Porosity Permeability data Samples from Core and Field Collection(current contract)

Sample Top Sample Area Well Name Top Depth Porosity Bulk Density Grain Density Permeability Stratigraphynumber (m and ft) Number (*) (m and ft) (%) (Kg/m3) (Kg/m3) Max (mD)

SP013 991.77m 13 Orangedale 225-5A 991.77m 4.10 2476 2580 0.12 Windsor GroupSP030 746.00ft 30 Malagawatch M-7 746 ft (227.4m) 0.60 2690 2705 0.04 Windsor GroupSP038 134.00m 38 Loch Lomond LL-04 134.00m 15.00 2265 2664 0.63 CumberlandSP048 577.00m 48 Loch Lomond Imperial 30-4 577.00m 9.00 2437 2678 0.05 MabouSP053 75.00ft 53 Lake Ainsle Lake Ainsle 88-1 75 ft (22.95m) 14.60 2254 2641 0.51 HortonSP079 223.00ft 79 Lake Ainsle Saarberg 8-4 223 ft (68m) 10.30 2425 2705 0.08 Windsor GroupSP126 0.00 126 Location 3 Ainslie Depocentre surface 25.20 1977 2642 105.09 HortonSP127 0.00 127 Location 14 Ainslie Depocentre surface 19.50 2142 2660 14.13 HortonSP128 0.00 128 Location 19 Ainslie Depocentre surface 16.50 2231 2673 8.27 HortonSP129 0.00 129 Location 20 Ainslie Depocentre surface 10.30 2397 2672 0.30 Horton

Horton

(*) For sample numbers see Table 2


For: NSDOE Reservoir Properties(data from current contract)

Various Well and Oupcrop samples (Western Cape Breton Subbasins)

Table 7a: Physical Properties of Sandstone and Limestone samples from the Western Cape Breton Subbasins(data from current contract)

Sample Number Sample Kmax Porosity Grain Remarks(see Table 2) Description Lithology Density

(sample no.) Stratigraphy(mD) (Percent) (kg/m3)

53 Lake Ainslie 88-1, 22.9m (75ft) Oil-stained sandsto 0.51 14.6 2641 Horton79 Saarberg 8-4 well, 68m (227ft) Carbonate (79) 0.08 10.3 2705 Windsor

126 Lake Ainslie Depocentre, Location 3 Sandstone (126) 105.1 25.2 2642 Horton127 Lake Ainslie Depocentre, Location 14 Sandstone (127) 14.1 19.5 2660 Horton128 Lake Ainslie Depocentre, Location 19 Sandstone (128) 8.3 16.5 2673 Horton129 Lake Ainslie Depocentre, Location 20 Sandstone (129) 0.3 10.3 2672 Horton

For Location of Samples see Figures 3b and 5

From: Global Geoenergy Research Ltd. Figure 7a August 12

For: NSDOE Reservoir Properties(selected samples under permission from Total Inc., 2004)


Table 7b: Physical Properties of Sandstone and Limestone samples from the Central Cape Breton Subbasins(Selected samples are from Mukhopadhyay, 2000) (*)

Sample Number Sample Kmax Porosity Grain Remarks(For details see Description Lithology DensityTable 2) (sample No.) Stratigraphy

(mD) (Percent) (kg/m3)13 Orangedale 225-5A, 991.8m Carbonate (13) 0.12 4.1 2580 Windsor30 Malagawatch M-7, 746.03ft (227.4m) Carbonate (30) 0.04 0.6 2705 Windsor

(*) LL-1-91 38.1m (*) Limestone 0.57 11.2 2720 Windsor(*) LL-1-91, 291.3m (888ft) (*) Limestone 0.05 8.2 2800 Windsor

38 LL-04, 134m Sandstone (38) 0.63 15.0 2664 Cumberland48 Imperial LL-30-4, 577m Sandstone (48) 0.05 9.0 2678 Mabou

(*) Sample data under permission of Total Inc., Calgary, Alberta (Mukhopadhyay, 2000)


For: NSDOE Reservoir Properties(data under permission from Total Inc., 2004)

Various Wells (Sydney Basin)(Mukhopadhyay, 2000)

Table 7c: Physical Properties of Sandstone and Limestone samples from the Sydney Subbasin(All samples are from Mukhopadhyay, 2000) (Permission from Total Inc., Calgary, Alberta)

Sample Number Sample K Porosity Grain Remarks(++) Description Lithology Air Density

StratigraphymD Percent kg/m3

(*) Ingonish #1 Box #2, 36' 8" Fractured Limesto 6.13 15.7 2890 Windsor(*) Ingonish #9 Box #5, 133' Sandstone 3.17 16.3 2630 Horton?(*) WR-84-1, 385.2 m Limestone <0.01 11.0 2680 Windsor(*) WR-84-1 Box 112, 537.5m Limestone 0.06 12.6 2780 Windsor(*) Kempthead 85-1, 13.8m Sandstone 3.51 17.9 2660 Mabou(*) Kempthead 85-1, 27.2m Sandstone 75.6 17.2 2670 Mabou(*) Sydney 82-1 626.4-626.55' Sandstone 0.04 8.7 2710 Cumberland(*) N.Sydney F-24, Core 4, 4466' Sandstone 1.39 12.8 2670 Mabou

(*) Sample data under permission of Total Inc., Calgary, Alberta (Mukhopadhyay, 2000)(++): For location of samples see Figure 14c

From: Global Geoenergy Research Ltd. Figure 7c October 26, 2004

Figures

Figure 1. Position of Maritimes Basin in relation to other Paleozoic Basins in Eastern North America

Figure 2a. Distribution of Carboniferous to Permian sediments within Maritimes Basin in Eastern Canada

Figure 2b. Carboniferous-Permian Basins of Nova Scotia with location of Study Area

Antigonish Basin

Western Cape Breton Subbasins

Central Cape BretonSubbasins

Sydney Subbasin

StudyArea

Figure 2b. Location of the Study Area within the Carboniferous-Permian Basins of Nova Scotia

Figure 3A. Regional geology of the southern Maritimes Basin

Figure 3b. Regional geology of Cape Breton Island

Figures 4 and 5 (large sizes) are within the pockets of the Final Report Binder

Figure 6a. Litho- and Chronostratigraphy of the Late Devonian to Permian sediments from Northern Nova Scotia with stratigraphic nomenclature for various subbasins from Cape Bretpn Island.

Figure 6b. A composite Lithostratigraphy of the Windsor Group from Central Cape Breton Subbasins (after Peter Giles, personal communication; Giles, 2001) (Permission from Total Inc., 2004; Mukhopadhyay 2000).

For Figures 7, 8, and 9, see within the pockets of

the Final Report Binder

Horton Group

Windsor Group

Mabou Group

Figure #10 Play Types in the Cape Breton Onshore Area

red and grey beds (potential source rocks)

Cumberland Group

Play Type #1: sandstone reservoirs in combinatin traps

Play Type #2: sandstone reservoirs associated with fault closures

Play Type #3: sandstone reservoirs in stratigraphic pinch-outs

Play Type #4: sandstone reservoirs in sub-salt positions

Play Type #5: carbonate bioherms

red and grey beds (potential source rocks)

Play Type #6: carbonates beneath evaporites

Play Type #7: carbonates in fault structures

Play Type #8: fractured carbonates

Play Type #10: sandstone reservoirs in alluvial channels

Figure 10. Conceptual Diagram of Petroleum Play Types (also as 11”X17” foldout within the Binder)

Figure 11a

Figure 11a. Location Map of petroleum seeps and oil-stains within various subbasins of Cape Breton Island. The numbers 1, 2,..6,.. etc. indicate total number of petroleum shows or seeps in that area.

Figure 11b. Windsor Group Carbonate Reservoir with crude oil, Well: ATG-8-76 (Jubilee area)

Figure 12a (i). Horton Source Rock shales (Type II and II-III) and thin Reservoir sands: Type Section -

Horton Bluffs

Photo: Bob Ryan

Figure 12a(i). Horton Group organic-rich shale and sandstone: Type Section – Horton Bluff – Windsor Subbasin

Figure 12a (ii): Horton Group shale and sandstone (Strathlorne Formation)(#location 13;

Figures 4 and 14a)

Photo:Billy Shaw

Figure 12 (ii): Horton Group shale and sandstone (Strathlorne Formation: Location #13; Western Cape Breton Subbasins (for exact location of #13, see Figure 5 in pocket of report binder)

Figure 12b (i). Black Limestone, Macumber formation (Windsor Group), Location #18, Western Cape Breton Subbasins

Photo: Billy Shaw

Figure 12b (i): Dark limestone from Macumber Formation (Lowermost Windsor Group), Location #18, Western Cape Breton Subbasins (for (for exact location of #13, see Figure 5 in pocket of report binder)

Figure 12b (ii). Well:LL-04 (Lock Lomond area) -Black Limestone (Windsor Group) (Table 2)

Photo: PKM

Figure 12b (ii): Dark limestone, Windsor Group, Well: LL-04, Loch Lomond area (for exact location of well, see Figure 5 in pocket of report binder)

Figure 12c. Mabou Group shale and sandstone: Cape Dauphin section, Sydney Basin

Photo: John Calder

Figure 12c: Dark organic-rich shale and sandstone from the Mabou Group, Cape Dauphin outcrop section, Sydney Subbasin (for exact location of Cape Dauphin section, see Figure 5 in pocket of report binder)

Figure 12d. Cumberland Group shale, coal, and sandstone: Joggins Section, Cumberland basin

Photo: John Calder

Figure 12d. A example of a sequence of coal, carbonaceous shale, and sandstone from the Cumberland Group, Joggins Section, Cumberland Basin (Western Nova Scotia; outside the current contract area; the exact location is not shown in any of the figures of this contract)

Figure 13a. Location #3 Horton Group porous sandstone, Lake Ainslie Depocentre

Photo: Billy Shaw

Figure 13a. Porous and permeable sandstone from the Horton Group, Location #3; Lake Ainslie Depocentre (for exact location of #3, see Figure 5 in pocket of report binder)

Figure 13b. Windsor Reservoir (FossiliferousLimestone), Cape Dauphin Section

Photo: John Calder

Figure 13b. Fossiliferous limestone (bioherm facies) reservoir, Windsor Group, Cape Dauphin Outcrop Section (for exact location of Cape Dauphin Section, see Figure 5 in pocket of report binder)

Figure 13c. Reservoir sandstone, Boss Point Formation, Cumberland Group

Photo: John Calder

Figure 13c. A typical example of a porous sandstone reservoir from the Boss Point Formation, Cumberland Group

Figure 13d. Salt and Evaporite within Windsor Group: Seal Rocks

Photo: PKM

Figure 13d. A typical example of the seal rock (salt and anhydrite) from the Middle Windsor Group

Figure 13e. Oil-stained evaporite associated with salt and fractured limestone, Windsor

Group, Jubilee area

Figure 13e. A typical oil-stained limestone and anhydrite reservoir rock from the Windsor Group, Bras D’Or subbasin (Jubilee area: well – ATG-49-77)

Fig. 13f.Typical example of 1.source (dark carbonate), 2. carrier bed (fractured anhydrite), 3. oil-stained reservoir (fractured anhydrite),

and 4. seal (impermeable anhydrite) rocks from the Windsor Group, Jubilee area

1

2

34

Photo: PKM

Figure 13f. An example of Petroleum System parameters within a single core section from the Windsor Group, Well: ATG-49-77, Bras-D’Or Subbasin (1: source rock; 2: carrier bed; 3: reservoir rock; and 4: seal rock)

Figure 14a. Geological map of Western Cape Breton Subbasins with well locations for samples (for details see Figure 5 in the pocket of the Report Binder).

Figure 14b. Geological map of Central Cape Breton Subbasins with location of wells for the samples (for details see Figure 5 in the pocket of the Report Binder)

Figure 14c. Geological map of Cape Breton Island (from NSDOE Printed map) with location of wells for the Sydney Subbasin (from Mukhopadhyay, 2000; permission from Total Inc., 2004)

0

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12

14

16

18

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5

TOTAL ORGANIC CARBON (TOC, wt.%)

REM

AIN

ING

HYD

RO

CA

RB

ON

PO

TEN

TIA

L (m

g H

C/g

Roc

k) Type I Oil Proneusu. lacustrine

TYPE II Oil Prone(usu. marine)

Mixed Type II / IIIOil / Gas Prone

Type IIIGas Prone

OrganicLean

DryGas Prone

Figure 15a. Remaining hydrocarbon potential vs. TOC showing the location of samples on the for the Mabou-Ainslie Subbasin; the oil-prone source rock is from Horton Group of Lake Ainslie 88-1 well

Figure 15b

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100

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300

400

500

600

700

800

900

1000

0 20 40 60 80 100 120 140 160 180 200

OXYGEN INDEX (OI, mg CO2/g TOC)

HYD

RO

GEN

IND

EX (H

I, m

g H

C /

g TO

C

Type IOil Prone

Type II (usu. marine)Oil Prone

M ixed Type II / IIIOil / Gas Prone

Type IIIGas Prone

Type IVGas Prone

Figure 15b. Kerogen Type (pseudo van Krevelen-Type) diagram showing the potential of sediments from the Mabou-Ainslie Subbasin

0

100

200

300

400

500

600

700

800

900

1000

330 380 430 480 530 580

Tmax (oC)

HYD

RO

GEN

IND

EX (m

g O

IL/g

TO

C

Type IOil Prone

Type IIOil Prone

(usu. marine)

Type IIIGas Prone

Type IV


~0.55% Ro

~01.40% Ro

Figure 15c. Kerogen Type determination of various samples from Mabou-Ainslie Subbasin based on Tmax vs. Hydrogen Index

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

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0.90

1.00

380 430 480 530 580

MATURITY (based on Tmax (oC))

PRO

DU

CTI

ON

IND

EX (P

I)

Con

dens

ate

Zone

Immature mature

Oil

Stained or Contaminated

Low Level Contamination High Level Contamination

Figure 15d. A plot of Tmax versus production index showing the position and HC Conversion of various samples from Mabou-Ainslie Subbasin

0

400

800

1200

1600

2000

2400

2800

3200

0 0.5 1 1.5 2 2.5 3

Vitrinite Reflectance (%Ro%)

Dep

th(m

)

Lake Ainsle 88-1Mull River #1Mary #1Port Hood #1Mabou #1

Figure 16. Maturity versus depth plots of various wells from the Mabou-Ainslie Subbasin

Figure 17. Liquid chromatography data of four samples from Western and Central Cape Breton Subbasins

Figure 18. Gas Chromatogram of the saturate fraction of oil extract from Lake Ainslie-88-1, 75ft

min30 40 50 60 70 80 90

pA

20

40

60

80

100

120

140

FID1 A, (F:\04-2477\SA84574A.D)

Figure 18: Gas chromatogram of the saturate fraction of the oil-stain from the reservoir sandstone of the Horton Group; Well: Ainslie-88-1, Mabou-Ainslie Subbasin.

Figure 19a Terpane and sterane mass fragmentograms for oil-stained sandstone, Ainslie-88-1, Mabou-Ainslie Subbasin

Figure 7: Cross-Plot of two biomarker parameters sensitive to thermal maturityfor bitumen extracted from four core samples

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.30 0.35 0.40 0.45 0.50 0.55 0.60 0.65 0.70

C32-hopane 22S/(22S+22R)

C29

-ste

rane

20S

/(20S

-20R

)

M-3

AGT-34-77

LL-04

L.Ainsle88-1

Peak O il Windowand higher

Early O ilWindow

Immature RockExtracts

Figure 19b

Figure 19b

Figure 19b. Plot of two maturity-sensitive saturate biomarker parameters with position of four oil-stain samples from the Mabou-Ainslie Subbasin and Central Cape Breton Subbasins

Figure 19cFigure 8: Comparison of the core bitumens based on source and environmental parameters, GGRL Project

0.50

1.00

1.50

2.00

2.50

0.00 0.50 1.00 1.50 2.00 2.50 3.00

C29-sterane/ C27-sterane

C30

* / C

29Ts

Rat

io

AGT-34-77 M-3 LL-04 L.Ainsle 88-1

Figure 19c

Figure 19c. A plot of two environmental sensitive saturate biomarker parameters (one is C29/C27 sterane) and position of four oil-stain samples from the Mabou-Ainslie and Central Cape Breton Subbasins

Figure 10: Comparison of the core bitumens based on depositional environment parameters, GGRL Project

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0.30

0.40

0.50

0.60

0.70

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00

C25-tricyclics / C26-tricyclics

Gam

mac

eran

e In

dex

(gam

mac

eran

e/ho

pane

)

AGT-34-77 M-3 LL-04 L.Ainsle 88-1

indicative of hypersaline depositional environment

Fig.19d

Figure 19d

Figure 19d. A plot of two environmental sensitive saturate biomarker parameters (C25/C26 tricyclics) and position of four oil-stain samples from the Mabou-Ainslie and Central Cape Breton Subbasins

Figure 19eFigure 9: Comparison of the core bitumens based on source and environment parameters GGRL Project

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0.10

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0.30

0.40

0.50

0.60

0.70

0.00 0.50 1.00 1.50 2.00 2.50 3.00

C29-sterane/ C27-sterane

Gam

mac

eran

e In

dex

(gam

mac

eran

e/ho

pane

)

AGT-34-77 M-3 LL-04 L.Ainsle 88-1

sample enriched in C29 stranes, bery low gammacerane

indicative of hypersaline depositional environment

Figure 19e: Comparison of stains from Mabou-Ainslie Subbasina and Central Cape Breton Subbasins

Figure 19e. A plot of two saturate biomarker parameter ratios (one is C29/C27 sterane and the other is gammacerane ratio) and position of four oil-stain samples from the Mabou-Ainslie and Central Cape Breton Subbasins

ST 29

St 27 St 2910 20 30 40 50 60 70 80 90

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70

80

9010

20

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60

70

80

90

AGT-34-77LL-04L. Ainsle 88-1M-3

Figure 19fSt 28

Figure 19f. Sterane C27, C28, and C29 distributions of four oil-stains, and bitumen extracts from Lake Ainslie-88-1 well (Mabou-Ainslie Subbasin) and the other three wells (shown above) from Central Cape Breton Subbasins..

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18

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REM

AIN

ING

HYD

RO

CA

RB

ON

PO

TEN

TIA

L (m

g H

C/g

Roc




Type IIIGas Prone

OrganicLean

DryGas Prone

Figure 20a

Figure 20a. Remaining Hydrocarbon Potential vs. TOC showing the location of samples for the Central Cape Breton Subbasin

0

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1000

0 20 40 60 80 100 120 140 160 180 200


HYD

RO

GEN

IND

EX (H

I, m

g H

C /

g TO

CType I

Oil Prone



Type IIIGas Prone

Type IVGas Prone

Figure 20b

Figure 20b. Kerogen Type (pseudo van Krevelen-Type) diagram showing the potential of sediments from various Central Cape Breton Subbasins

0

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300

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600

700

800

900

1000

330 380 430 480 530 580

Tmax (oC)

HYD

RO

GEN

IND

EX (m

g O

IL/g

TO

CType I

Oil Prone(usu. lacustrine)

Type IIOil Prone

(usu. marine)

Type IIIGas Prone

Type IV


~0.55% Ro

~01.40% Ro

Figure 20c

Figure 20c. Kerogen Type determination of various samples from Central Cape Breton Subbasins based on Tmax vs. Hydrogen Index

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PRO

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CTI

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IND

EX (P

I)

Con

dens

ate

Zone

Immature Zone

Oil Zone

Stained orContaminated

Low Level Conversion High Level Conversion

Figure 20d

Figure 20d. A plot of Tmax versus production index showing the position and HC Conversion of various samples from Central Cape Breton Subbasins

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Dep

th (m

)

Jubilee

Orangedale225

Malaga M-5A

Malaga M-9

Bras D'Or 9-78

LL-04

Imperial LL-30-4

Cleveland 227-2

McIvor Pt #R-1

Cerro Mining #71-3

Figure 21. Maturity versus depth plots of various wells from the Central Cape Breton Subbasins

Figure 22. Liquid chromatography data of four samples from Central Cape Breton Subbasins and Sydney Subbasin (data from Total Fina Report, 2000; permission from Total Inc., 2004)

Figure 23: Gas Chromatograms of saturate fraction of bitumen/oil-stains (3 selected wells)

min30 40 50 60 70 80 90

pA

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FID1 A, (F:\04-2477\SA84539A.D) n

-C11

n-C

12 i-

C13

i-C

14 n

-C13

i-C

15 n

-C14

i-C

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-C15

n-C

16 i-

C18

n-C

17 Pr

n-C

18 P

hy n

-C19

n-C

20 n-C

21 n-C

22 n-C

23 n-C

24 n

-C25

n-C

26 n

-C27

n-C

28

n-C

29

n-C

30

n-C

31

n-C

32

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34

n-C

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n-C

40

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pA

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FID1 A, (F:\04-2477\SA84559A.D)

n-C

10 n-C

11

n-C

12 i-

C13 i-

C14

n-C

13

i-C

15 n

-C14

i-C

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-C15

n-C

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C18

n-C

17 P

r n

-C18

Phy

n-C

19 n

-C20

n-C

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-C22

n-C

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-C24

n-C

25 n

-C26

n-C

27

n-C

28

n-C

29

n-C

30

n-C

31

n-C

32

n-C

33

n-C

34

n-C

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n-C

36

min30 40 50 60 70 80 90

pA

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FID1 A, (F:\04-2477\SA84563A.D)

n-C

11 n-C

12 i-

C13

i-C

14 n

-C13

i-C

15 n

-C14

i-C

16 n

-C15

n-C

16 i-

C18

n-C

17 P

r n

-C18

Phy

n-C

19 n

-C20

n-C

21 n

-C22

n-C

23 n

-C24

n-C

25 n

-C26

n-C

27 n

-C28

n-C

29

n-C

30

n-C

31

n-C

32

AGT-34-77

M-3

LL-04

(i)

(ii)

(iii)

Figure 23a. Gas chromatograms of the saturate fraction of the extract of samples from three wells from Central Subbasins: i. AGT-34-77; ii. M-3; and iii. LL-04.

Figure 23b. Gas chromatograms of the saturate fraction of the extract of one sample from the Jubilee area well, Central Cape Breton Subbasin (data taken from Total Fina Contract, 2000; permission from Total Inc., 2004)

Figure 23c. Gas chromatograms of the saturate fraction of the extract of one sample from the McIver Pt #1 well, Central Cape Breton Subbasin (data taken from Total Fina Contract, 2000; permission from Total Inc., 2004)

Figure 23d. Gas chromatograms of the saturate fraction of the extract of one sample from the McIver Pt #1 well, Central Cape Breton Subbasin (data taken from Total Fina Contract, 2000; permission from Total Inc., 2004)

Figure 23e. Gas chromatograms of the saturate fraction of the crude oil from the Malagawatch M-9 well, Central Cape Breton Subbasin (data taken from Total Fina Contract, 2000; permission from Total Inc., 2004)

Figure 24a. Terpane and sterane mass fragmentograms of oil stains from ATG-34-77 well (357.8 ft or 108.9 m), Central Cape Breton Subbasins

Figure 24b. Terpane and sterane mass fragmentograms of oil stains from Malagawatch M-3 well (1104.4m), Central Cape Breton Subbasin

Figure 24c. Terpane and sterane mass fragmentograms of oil stains from LL-04 well (196.48m), Central Cape Breton Subbasin

(i)

(ii) Figure 24d. Terpane (i) and sterane (ii)mass fragmentograms of oil stain from ATG-17-77 well (218 ft or 66.4 m), Central Cape Breton Subbasin (data taken from Total Fina Contract, 2000; permission from Total Inc., 2004)

(i)

(ii) Figure 24e. Terpane (i) and sterane (ii)mass fragmentograms of oil stain from McIver Pt #1 well (149.7 ft or 45.62 m), Central Cape Breton Subbasin (data taken from Total Fina Contract, 2000; permission from Total Inc., 2004)

(i)

Figure 24f. Terpane (i) and sterane (ii)mass fragmentograms of oil stain from McIver Pt #1 well (896 ft or 273.1 m), Central Cape Breton Subbasin (data taken from Total Fina Contract, 2000; permission from Total Inc., 2004)

(i)

Figure 24g. Terpane (i) and sterane (ii)mass fragmentograms from saturate biomarkers of crude oil from Malagawatch M-9 well (depth:?), Central Cape Breton Subbasin (data taken from Total Fina Contract, 2000; permission from Total Inc., 2004)

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AIN

ING

HYD

RO

CA

RB

ON

PO

TEN

TIA

L (m

g H

C/g

Roc




Type IIIGas Prone

OrganicLean

DryGas Prone

Figure 25a

Figure 25a. Remaining hydrocarbon potential vs. TOC showing the location of samples on the graph for the Sydney Basin (from Total Fina Contract, 2000; permission from Total Inc., 2004)

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RO

GEN

IND

EX (H

I, m

g H

C /

g TO

CType I

Oil Prone



Type IIIGas Prone

Type IVGas Prone

Figure 25b

Figure 25b. Kerogen Type (pseudo van Krevelen-Type) diagram showing the potential of sediments from various of the Sydney Basin (from Total Fina Contract, 2000; permission from Total Inc., 2004)

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Tmax (oC)

HYD

RO

GEN

IND

EX (m

g O

IL/g

TO

CType I

Oil Prone(usu. lacustrine)

Type IIOil Prone

(usu. marine)

Type IIIGas Prone

Type IV


~0.55% Ro

~01.40% Ro

Figure 25c

Figure 25c. Kerogen Type determination of various samples from Sydney Basin based on Tmax vs. Hydrogen Index (from Mukhopadhyay, 2000; permission from Total Inc., 2004)

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ON

IND

EX (P

I)

Con

dens

ate

Zone

Figure 25d

Immature

Stained or Contaminated

Oil Zone

Low levelConversion

High level Conversion

Gas Zone

Figure 25d. A plot of Tmax versus Production Index showing the position and HC Conversion of various samples from the Sydney Basin (from Total Fina Contract, 2000; permission from Total Inc., 2004)

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700

0 0.5 1 1.5 2

Ro%

Dep

th (m

)

Kempthead-84-1

WR-84-1NSDME #1 (6609)

NC-87-1

#REF!

Figure 26a. Maturity versus depth plots of various wells from the Sydney Basin (onshore wells) (from Mukhopadhyay, 2000; permission from Total Inc., 2004)

1

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Ro%

Dep

th (m

)

N. Sydney F-24

N. Sydney P-05

Figure 26b. Maturity versus depth plots of two offshore wells from the Sydney Basin (from Mukhopadhyay, 2000; permission from Total Inc., 2004)

(a)

(b) Figure 27. Gas chromatograms of the saturate fraction of the extract of samples from two wells from the Sydney Basin: a. Ingonish #1 well; b. North Sydney F-24 (from Mukhopadhyay, 2000; permission from Total Inc., 2004)

(i)

(ii) Figure 28a. Terpane (m/z 191) and sterane (217) mass fragmentograms of oil stains from Ingonish #1 well, Sydney Basin (from Mukhopadhyay, 2000; permission from Total Inc., 2004)

(i)

(ii) Figure 28b. Terpane (m/z 191) and sterane (217) mass fragmentograms of oil stains from North Sydney F-24 (offshore), Sydney Basin (from Mukhopadhyay, 2000; permission from Total Inc., 2004)

APPENDICES

APPENDIX A ANALYTICAL METHODS: PETROLEUM GEOCHEMISTRY A.1. Total Organic Carbon Determination by Leco Carbon Analyzer Total organic carbon (TOC) is best determined by direct combustion.

Approximately 0.2 grams of sample were carefully weighed, treated with

concentrated HCl to remove carbonates, and vacuum filtered on glass fiber

paper. The residue and paper were placed in a ceramic crucible, dried,

combusted with pure oxygen in a LECO EC-12 carbon analyzer at about 1000oC.

A laboratory standard is run every five minutes. ‘Total Carbonate’ can be

determined from differences in weight of the original sample and residue that

remained after acid treatment or by LECO combustion TOC differences before

and after the acid digestion. For organic carbon determination, seventy-five (75)

samples have been analyzed (Table 2c) for the current contract and fifty-one (51)

samples in the Total Fina Contract in 2000.

A.2. Rock-Eval Pyrolysis Rock-Eval II pyrolysis was used to determine kerogen type (S2 and HI [hydrogen

index, mg HC/g TOC]), kerogen maturity [Tmax (oC)], amount of free hydrocarbons

(S1 and PI [production index; S1/S1+S2]), and oxygen concentration (S3 or mg

CO2/g TOC) of the kerogen. About 0.1 gm of the same ground sample used for

LECO TOC is carefully weighed in a pyrolysis crucible and then heated to 300oC to

determine the amount of free hydrocarbons, S1, which is thermally distilled. The

amount of pyrolyzable hydrocarbons, S2, is measured when the sample is heated in

an inert atmosphere between 300o to 550o C using a heating rate of 25oC/minute.

S1 and S2 are reported in mg HC/g of sample. Tmax, a maturity indicator, is the

temperature of maximum S2 generation. The S2 values less than 0.2 mg HC/g

sample has poor definition of the S2-maximum. Accordingly, the Tmax cannot be

determined reliably (Peters, 1986). Carbon dioxide is also being generated during

kerogen pyrolysis. The resulting peak S3 is an indicator of original oxidation during

sediment deposition. It is collected up to a temperature of 390oC and reported as S3

in units of mg CO2/g sample. A laboratory standard is run every 10 samples. Both

the Hydrogen Index (HI = S2 * 100/TOC) and Oxygen Index (OI = S3 *100/TOC)

values are used as pseudo-van Krevelen-Type diagram. For details of the Rock-

Eval pyrolysis, see Espitalie et al. (1985), Peters (1986), and Hunt (1995). Fifty (50)

samples have been analyzed for Rock-Eval pyrolysis from the current contract in

2004 and fifty-one (51) samples for the Total Fina contract in 2000.

A.3. Vitrinite Reflectance Analysis For vitrinite reflectance measurement, all selected forty (40) whole rock samples

were subjected to kerogen isolation by acid (HCl and HF) treatment and heavy

liquid separation. For details of kerogen isolation procedures, please review

previous works (Durand, 1980; Tissot and Welte, 1984; Mukhopadhyay, 1992).

Two types of sample preparation were made from isolated kerogen: polished plug

and smear slide. Vitrinite reflectance was determined using a ZEISS Axioskop

Incident Light Microscope and standard procedures (ASTM, 1991; Stach et al.,

1982; Mukhopadhyay, 1992). The reflectance was measured with an oil immersion

objective (40X). The reflectance measurement was calibrated with three glass

standards of 0.94%, 1.01% and 1.69% Ro acquired from Leitz and Zeiss Canada.

Usually 50 vitrinite grains were measured for each sample. For this work, random

vitrinite reflectance was measured. For more details about the vitrinite reflectance

procedures and interpretation of vitrinite reflectance measurement, see Dow

(1977), Mukhopadhyay (1992, 1994). Twenty-seven samples have been analyzed

for vitrinite reflectance measurement.

A.4. Wet Chemistry, Gas Chromatography, and Gas Chromatography-

Mass Spectrometry

A.4.1. Solvent extraction and fractionation of the bitumen and oil

The soluble organic matter (bitumen) in the rock has been extracted by organic

solvent. The extracted bitumen and the submitted oil samples were fractionated

(by column chromatography) into saturated hydrocarbon, aromatic hydrocarbon

and polar fractions. The type and amount of bitumen extracted and/or oil

depends largely upon the nature of the contained organic matter and its level of

maturity. Asphaltenes are precipitated with hexane and the soluble fraction is

separated into saturates, aromatics and resin (NSO compounds) on a silica-

alumina column by successive elutions with hexane, benzene and benzene-

methanol. The solvents were evaporated and the weight percent of each

component is determined.

A.4.2. Gas chromatography (GC) of C8+-alkanes

The alkane (saturated) fractions of the bitumens were further analyzed by high

resolution GC to determine their distributions. The saturate fraction is analyzed

with a Varian model 3400 gas chromatograph fitted with Quadrex 50-meter fused

silica capillary column. The gas chromatograph was programmed from 40oC at

10oC/minute with a 2-minute hold at 40oC and a 20-minute hold at 340oC.

Analytical data was processed with a Nelson Analytical model 3000

chromatography data system and IBM computer hardware. The interpretation of

alkane distribution, including pristane/phytane, pristane/n-C17, and phytane/n-C18

ratios can yield much confirmatory information in source rock evaluation.

A.4.3. Gas chromatography-Mass spectrometry (GC-MS) of biomarkers

Saturate biomarkers of the bitumens were further investigated using GC-MS

method. The saturate fraction of the source rock extract and oil-stains that was

isolated by liquid chromatography, was injected into a HP5890 gas

chromatograph coupled to a HP5971A Mass Selective Detector (MSD). The

isomerization of the biological markers (steranes, triterpanes) is exploited by

petroleum geochemists for maturity evaluation and paleoenvironment of the

deposition of crude oils and/or source rocks.

In describing the specific compounds, chemical conventions are used to

delineate specific structural differences. Alpha “α” or beta “β” designations refer

to orientation of carbon-hydrogen bonds in the ring system. Alpha (α) refers to

orientation above the plane of the ring, whereas beta (β) is below the plane. The

S and R designations are chemical conventions for designating molecular chiral

centers in the hydrocarbon chains. R designates clockwise, whereas S is

counter-clockwise orientation in these sequencing rules.

The data discussed in this report are restricted to two classes of biomarker

compounds referred to as terpanes and steranes. The Sselected Ion Monitoring

(SIM) feature of the GC/MS data acquisition system permits specific ions to be

monitored. Ions with mass/charge m/z 191 allow characterization of specific

triterpenoid compounds, while ions with m/z 217 are diagnostic for steranes.

Steranes with different chemical structures can be identified using different ions.

Thus, m/z 218 is characterized with steranes with abb stereochemistry and

diasteranes exhibit a pronounced m/z 259 fragment.

The biomarker compounds referred to as terpanes are mainly derived from

bacterial (prokaryotic) membrane lipids. Of these, a number of the possible 3-ring

(tricyclic), 4-ring (tetracyclic), and 5-ring (pentacyclic) compounds will be

evaluated in this report. The different molecular configurations of these

compounds provide useful insight to the stained reservoir rock and source rock

habitat and degree of thermal stress experienced

APPENDIX B ANALYTICAL METHODS: RESERVOIR ANALYSIS.

B.1. Gas Porosimetry Analysis For the purposes of oil and gas exploration & development, porosity is used to

determine a reservoir's size and production capabilities. As a petrophysical

characteristic, porosity is defined as the proportional relationship of a rock's pore

(and/or void) volume compared to its total (bulk) volume. This value is expressed

as a percentage (i.e. 12.0%) or a decimal (i.e. 0.120). The total (bulk) volume of

a sample is the sum of two separate volumes: Pore Volume + Grain Volume.

Porosity = Pore Volume ÷ Bulk Volume Bulk Volume = Grain Volume + Pore (and/or Void) Volume

In petrophysical samples, "void" volume is generally attributed to vugs. At

AGAT Laboratories, the standard operating procedure for determining an

unknown porosity is the Boyle's Law Gas Porosimetry method which is a

combination of two separate processes: a bulk volume measurement and a

grain volume measurement, both performed in a Boyle's Law Gas

Porosimeter. From these two measurements, the pore volume is determined

so that the porosity can be calculated. The Boyle's Law Gas Porosimeter is

generally used for consolidated core samples (routine core analysis) while

unconsolidated core samples are treated as overburden samples (which is a

different process). The Boyle's Law Gas Porosimeter at AGAT Laboratories

measures a sample's grain volume. The principle used in determining this

measurement is, as the name implies, Boyle's Law of Gases. In a closed

equilibrium system, a reference (known) volume of gas (Vi) multiplied by its

initial pressure (Pi) will be equal to the equilibrium pressure (Pe) of the gas

multiplied by the second volume (Ve) when the temperature remains constant.

Due to its small molecular size and inert nature allowing a more rapid and

complete absorption into a petrophysical sample Helium gas is used in the

Boyle's Law Gas Porosimeter ( or "Porosimeter" for short).

Pi × Vi = Pe × Ve where Ti = Te

The second value in the porosity equation, Bulk Volume, can be measured in

one of two ways: Direct Measurement (Calipering), or Medium Displacement

(Principle of Archimedes). Direct Measurement, the more common of the two

methods involves calipering a sample's length and diameter dimensions to

determine its bulk volume. Samples must be of uniform, cylindrical shape for

this method to be applied accurately. The principle behind this method is the

geometrical equation used to calculate a cylinder's volume: pi multiplied by

the length multiplied by the radius squared. Calipered measurements are

reported in centimeters (to a tenth of a millimeter) while bulk volumes are

calculated to cubic centimeters (cc).

BV = � × l × r2 for uniform cylinders The second method of bulk volume determination, Medium Displacement,

should only be used when a calipered volume would be inaccurate (i.e. when

a sample is broken, fragmented, corkscrewed or grossly irregular). Water is

used in the displacement method, which provides Water Bulk volume. By

including a mass measurement into the set of equations, density may be

derived from dividing the sample's mass by an appropriate volume. Two

densities are usually reported: Bulk Density and Grain Density. Bulk density is

a sample's mass divided by its bulk volume while grain density is the mass

divided by grain volume, assuming that the pore mass is equal to zero. Both

density values are reported in units of kilograms per cubic meter (i.e. a grain

density for sandstone would be recorded as 2650 kg/cubic meter or simply

2650).

Density = Mass ÷ Volume The gauge used to read helium pressures within a Boyle's Law Gas

Porosimeter at AGAT Laboratories is a Heise digital gauge (Model 701A)

which displays a reading to the hundredth of a psi (pound per square inch).

All porosity values obtained by this method are reported at three significant

figures. The smaller, digital calipers will measure to a hundredth of a

millimeter (this value is generally rounded off to the nearest tenth of a

millimeter) while the larger, manual calipers measure to a tenth of a

millimeter. Porosity values determined by the Boyle's Law Gas porosimetry

method are given a margin of error of plus or minus 0.005 (+/- half of a

percent). Negative porosity values are impossible (at least from a

petrophysical standpoint). Therefore, any porosity value of less than 0.005

must be rounded up to 0.005 so that the range does not include a negative

value.

NOTE: 0.005 is the minimum reportable porosity value.

Method validation is obtained once a quality control test sample is ran for

the desired chamber size (1.0", 1.5", or full diameter) and results in

porosity and density values which do not exceed a defined range. The

obtained values will be entered into a Quality Control Chart and must fall

within three standard deviations of the reference mean for that sample.

B.2. Axial Flow Permeability Measurement

Permeability is the characteristic that allows fluid (gas) to flow through a

substrate. A single sheet of paper towel would have a high permeability

while the rubber inner tube of a tire would not (so long, as there are no

punctures or tears in the rubber). Permeability is measured in Darcies. A

porous medium has a permeability of one Darcy when a single-phase fluid

of one centipoise viscosity that completely fills the voids of the medium will

flow through it. Under the "conditions of Stoke's flow" at a rate of one

millimeter per second per square centimeter of cross-sectional area under

a pressure gradient of one atmosphere per centimeter.

"Stokes flow conditions" basically states that the rate of flow must be

sufficiently low and directly proportional to the pressure gradient. Darcies

would be the unit of measurement to determine water flow rates across water-

saturated coffee grounds in a low temperature coffee percolator. Since very

few rocks will have this degree of permeability, petrophysical permeability’s

are measured in milliDarcies (mD), one thousandths of a Darcy.

At AGAT Laboratories, there are a variety of permeability-measuring devices

for petrophysical permeabilities. This is the standard operating procedure for

routine core analysis in a steady state nitrogen permeameter in which the

sample is held within a Hassler-type Core Holder. These permeameters

measure a nitrogen pressure differential through a cross section of rock.

Permeability values obtained in the lab environment become an important

index for oil and gas exploration/development in determining reservoir flow

rates and feasibility.

The determination of permeability involves the measurement of a flow rate of

a fluid (gas) of known viscosity through a sample under a measured pressure

differential, once a steady state of flow has been achieved. While Darcy

originally intended for only liquid permeabilities to be determined this way,

Klinkenberg showed that extrapolated gas permeability is equal to the non-

reactive liquid permeability (the Klinkenberg Effect). This type of permeability

measurement is referred to as a "Klinkenberg Permeability" and is the type

used for routine core analysis. The routine core analysis permeameters rely

on a Hassler-type sample holder to allow nitrogen to enter and leave the

sample only through diametrically opposed openings of a referenced area.

Nitrogen is used as the gas for these permeability measurements because of

its availability and simplicity. A Fine Nitrogen Regulator controls the initial

nitrogen pressure entering the sample (“upstream pressure”). The rate at

which that nitrogen is permitted to flow across a sample and emerge on the

opposite side ("downstream pressure") is a function of the sample's

permeability in that direction. The difference between these two pressure

values is the pressure gradient. Pressure gradients alone, even with a gas of

known viscosity, are not enough to calculate permeability, as a flow rate is

required. Flow rates are determined by the use of orifices, (small stainless

steel tubing). Orifices have a predetermined flow rate that limits the escape of

nitrogen that has emerged from the sample. Excess downstream pressure

which the orifice can not accommodate becomes "back" pressure, which is

used to push water up a manometer or graduated cylinder (much like a

barometer uses atmospheric pressure). It is the combination of these three

values (the pressure gradient across a sample, known flow rate through an

orifice, and excess pressure) that are used to calculate a sample's

permeability.

Detection limits for the routine core analysis permeability meters have

been restricted to a range of one thousandth of a milliDarcy (0.001mD) to

ten thousand milliDarcies (10,000 mD). Values that are measured outside

of this range are reported as less than 0.001 mD and greater than 10,000

mD respectively. All values are reported in milliDarcies, an industry

standard for the unit of permeability.

Method validation is performed by running quality control samples for each

orifice of the permeability meter. These values are calculated by a

computer program (Calculations > Permeability >Vertical) and entered into

the appropriate quality control program chart. Each quality control sample

has a referenced mean. Obtained values must fall within three standard

deviations of the referenced mean (Control Limit).

Leco HGS Well TOC S1 S2 Tmax HI PI

No. Id. (oC)

Horton Group Long Pond 0.77 0.00 0.01 350 1 0.80 Horton Group 1 0.07 0.01 0.02 326 29 0.33 Horton Group 1 0.18 0.01 0.06 436 33 0.14 Horton Group 1 0.36 0.01 0.03 365 8 0.25 Horton Group 1 0.34 0.00 0.14 443 41 0.00 Horton Group 12 0.46 0.11 0.11 426 24 0.50 Horton Group 12 0.33 0.04 0.00 311 0 1.00 Horton Group 12 0.33 0.09 0.17 406 52 0.35 Horton Group 12 0.40 0.02 0.08 443 20 0.20 Horton Group 3 0.09 0.02 0.10 362 111 0.17 Horton Group 13 0.11 0.00 0.00 257 0 0.00 Horton Group 13 0.11 0.00 0.05 321 45 0.14 Horton Group 24 0.33 0.04 0.24 451 73 0.07 Horton Group 27 0.29 0.01 0.14 447 48 0.19 Horton Group 27 0.41 0.03 0.13 443 32 0.09 Horton Group 33 0.92 0.02 2.30 434 250 0.20 Horton Group Aberdee Bank 0.31 0.01 0.04 284 13 0.40 Horton Group 41 1.06 0.06 0.09 282 8 0.22 Horton Group Mull R 0.13 0.02 0.07 443 54 0.35 Horton Group Mull R 0.37 0.09 0.17 436 46 0.38 Horton Group McIsaac Pt 0.34 0.03 0.05 436 15 0.29 Horton Group Twin Rock 0.23 0.08 0.20 439 87 0.06 Horton Group Twin Rock 0.14 0.01 0.15 443 107 0.20 Horton Group Trout Bk 0.35 0.02 0.08 432 23 0.22

Appendix C-1a. Rock-Eval pyrolysis data (from Humblin, 1989)

0

100

200

300

400

500

600

700

800

900

1000

330 380 430 480 530 580

Tmax (oC)

HYD

RO

GEN

IND

EX (m

g O

IL/g

TO

C

Type IOil Prone

(usu. lacustrine)

Type IIOil Prone

(usu. marine)

Type IIIGas Prone

Type IV


~0.55% Ro

~01.40% Ro

Appendix C-1b

Appendix C-1b. Source Rock Potential Diagram as Tmax vs Hydrogen Index plot (prepared based on data from Hamblin, 1989)

Appendix C-1c. Maturation map of Cape Breton Island based on Thermal Alteration Indices (Humblin and Utting, 1991)

Appendix C-2a. Location map of analyzed samples from Cape Breton Island (from Mukhopadhyay, 1991).

Appendix C-2b. Hydrocarbon potential of selected sediments of the Windsor Group from the Western Cape Breton Subbasins.

Appendix C-2c. Hydrocarbon potential of selected sediments of the Windsor Group from the Central Cape Breton Subbasins.

Appendix C-2d. Hydrocarbon potential of selected sediments of the Windsor Group from Sydney Basin.

For: NSDOE Source Rock Evaluation Data Project: Colindale Member, Western Cape Breton(Tammy Allen's M.Sc. Thesis)

ORGANIC CARBON AND ROCK-EVAL PYROLYSIS DATA

Tammy Allen's Masters ThesisWestern Cape Breton SubbasinsColindale Member, Mabou Group

SAMPLE IDENTIFICATION TOC S1 S2 S3 Tmax S1/ HI OI S2/ PISample Wt% mg/g mg/g mg/g degC TOC S3Number

RESR8-11 1.62 0.11 3.42 0.80 443 211 49 0.03RESR8-14 2.75 0.18 5.58 1.13 442 203 41 0.03

RESR8-17 3.29 0.38 10.29 1.63 447 313 50 0.04

RESR8-20 1.17 0.08 1.10 2.08 438 94 178 0.07

RESR8-23 0.75 0.02 0.39 1.01 436 52 135 0.05

RESR8-26 1.08 0.04 1.17 0.30 443 108 28 0.03

RESR8-29 0.37 0.03 0.16 0.92 430 43 249 0.16

RESR8-32 1.35 0.61 1.69 1.15 441 125 85 0.27

RESR8-35 0.58 0.04 0.26 0.70 446 45 121 0.13

RESR8-38 0.67 0.04 0.58 0.99 438 87 148 0.06

RESR8-39.5 0.59 0.20 0.59 0.76 447 100 129 0.25

RESR8-40.5 3.74 0.87 9.33 0.42 443 250 11 0.09

RESR8-41.5 1.27 0.08 2.08 0.31 439 164 24 0.04

RESR8-42.5 0.46 0.27 0.28 0.69 442 61 150 0.49

RESR8-45.5 0.37 0.21 0.21 0.60 411 57 162 0.50

RESR8-50.08 2.36 0.24 6.12 0.62 444 259 26 0.04

RESR8-51.17 1.44 0.07 1.96 0.53 442 136 37 0.03

RESR8-52.45 1.04 0.45 1.27 0.73 444 122 70 0.26

RESR8-60.5 0.21 0.03 0.04 0.36 457 19 171 0.43

RESR8-63.52 0.38 0.02 0.08 0.68 507 21 179 0.20

RESR8-66.7 0.32 0.15 0.14 0.56 433 44 175 0.52

RESR8-72.5 0.22 0.16 0.09 0.37 377 41 168 0.64

RESR8-75.5 0.60 0.49 0.19 0.06 423 32 10 0.72

RESR8-78.78 0.32 0.02 0.06 0.17 445 19 53 0.25

RESR8-83.16 0.39 0.24 0.13 0.18 415 33 46 0.65

RESR8-85.94 0.95 0.76 0.21 0.39 426 22 41 0.78

RESR8-89.4 0.28 0.03 0.07 0.10 421 25 36 0.30

RESR8-93.1 0.56 0.35 0.37 0.15 436 66 27 0.49

RESR8-95.56 1.23 0.44 1.30 0.27 440 106 22 0.25

RESR8-102.02 0.41 0.25 0.17 0.13 443 42 32 0.60

RESR8-404.96 2.92 0.11 3.07 0.42 441 105 14 0.03

RESR8-109.5 0.59 0.03 0.15 0.22 437 25 37 0.17

RESR8-113 0.31 0.05 0.05 0.11 418 16 36 0.50

RESR8-113.3 0.27 0.04 0.03 0.11 376 11 41 0.57

RESR8-113.63 0.92 0.04 0.67 0.22 439 73 24 0.06

RESR8-113.82 1.90 0.07 2.50 1.19 441 132 63 0.03

RESR8-114.03 1.83 0.16 2.44 0.10 445 133 6 0.06

RESR8-114.13 2.87 0.14 4.59 0.19 445 160 7 0.03

RESR8-114.4 2.52 0.13 3.69 0.77 445 146 31 0.03

RESR8-114.74 2.09 0.38 2.48 1.22 443 119 58 0.13

RESR8--115.25 1.72 0.10 1.94 0.89 445 113 52 0.05

RESR8-115.54 1.91 0.16 2.33 1.04 442 122 55 0.06

RESR8-115.84 2.28 0.12 3.08 0.14 443 135 6 0.04

RESR8-116.14 1.95 0.13 3.12 0.63 443 160 32 0.04

RESR8-116.43 1.89 0.10 2.18 1.10 445 115 58 0.04

RESR8-116.67 2.68 0.16 4.24 0.07 444 158 3 0.04

RESR8-116.98 1.35 0.08 1.30 0.22 440 96 16 0.06

RESR8-117.27 2.29 0.15 3.38 0.63 442 148 28 0.04

RESR8-117.56 2.08 0.11 2.78 0.50 446 134 24 0.04

RESR8-117.78 2.82 0.16 4.11 0.54 442 146 19 0.04

RESR8-118.1 2.43 0.31 2.54 0.80 443 105 33 0.11

RESR8-118.4 2.35 0.10 2.40 0.46 443 102 20 0.04

RESR8-118.7 2.78 0.17 3.56 0.56 444 128 20 0.05

RESR8-119 0.58 0.07 0.16 0.30 431 28 52 0.30

ID

From: Global geoenergy Research Ltd.Appendix C-3a

1 August 12, 2004





RESR8-11 1.62 0.11 3.42 0.80 443 211 49 0.03

ID

RESR8-119.3 0.43 0.51 0.46 0.49 440 107 114 0.53

RESR8-120.3 0.35 0.04 0.20 0.36 441 57 103 0.17

RESR8-121.3 0.60 0.04 0.21 0.40 444 35 67 0.16

RESR8-122.3 0.39 0.02 0.13 0.27 432 33 69 0.13

RESR8-123.3 1.86 0.15 3.27 0.23 443 176 12 0.04

RESR8-124.3 0.42 0.04 0.20 0.06 428 48 14 0.17

RESR8-125.5 0.52 0.04 0.29 0.10 434 56 19 0.12

RESR8-126.5 3.02 0.20 5.35 0.26 443 177 9 0.04

RESR8-127.5 0.65 0.04 0.40 0.17 442 62 26 0.09

RESR8-128.5 0.60 0.08 0.22 0.12 482 37 20 0.27

RESR8-132.75 0.39 0.04 0.13 0.08 471 33 21 0.24

RESR8-136.2 2.48 0.10 3.97 0.56 444 160 23 0.02

RESR8-155.48 0.97 0.11 1.10 0.36 444 113 37 0.09

RESR8-158.34 0.53 0.07 0.25 0.14 443 47 26 0.22

RESR8-162.5 0.18 0.03 0.08 0.24 398 44 133 0.27

RESR8-165.4 0.25 0.05 0.06 0.32 439 24 128 0.45RESR8-167.95 0.20 0.04 0.10 0.17 470 50 85 0.29

RESR8-175.6 0.48 0.05 0.09 0.11 466 19 23 0.36

RESR8-176.8 1.38 0.31 2.27 0.13 443 165 9 0.12

RESR8-177 1.95 0.13 3.05 0.24 443 156 12 0.04

RESR8-180.9 0.49 0.34 0.23 0.27 433 47 55 0.60

RESR12-26.36 4.73 0.29 3.42 0.93 429 72 20 0.08

RESR12-31.5 3.21 0.22 3.22 1.01 435 100 32 0.06

RESR12-35.1 4.44 0.18 0.70 1.00 490 16 23 0.20

RESR12-38.10 2.40 0.16 0.68 0.58 433 28 24 0.19

RESR12-65.2 0.64 0.15 0.34 0.22 423 53 34 0.31

RESR12-68.1 0.41 0.21 0.13 0.27 367 32 66 0.62

RESR12-71.1 19.20 0.55 26.83 2.82 429 140 15 0.02

RESR12-82.85 0.82 0.05 0.55 0.49 445 67 60 0.08

RESR12-86.6 0.73 0.43 0.39 0.56 405 53 77 0.52RESR12-107.8 0.51 0.14 0.30 0.33 363 59 65 0.32RESR12-110.9 0.47 0.14 0.35 0.26 374 75 55 0.29RESR12-114.5 0.49 0.01 0.17 0.15 324 35 31 0.06RESR12-118.15 37.00 6.92 59.92 2.90 421 162 8 0.10RESR12-121.5 0.59 0.49 0.10 0.90 384 17 153 0.83RESR12-124.5 1.32 0.57 0.23 0.82 326 17 62 0.71RESR12-163.05 19.30 0.85 15.46 2.97 428 80 15 0.05RESR12-163.8 16.30 0.52 13.89 2.52 427 85 16 0.04RESR12-164.57 12.00 0.65 6.62 2.16 431 55 18 0.09RESR12-167.3 1.11 0.25 0.18 0.92 435 16 83 0.58RESR12-170.25 0.32 0.12 0.10 0.55 387 31 172 0.55RESR12-172.6 3.89 0.08 0.85 0.62 425 22 16 0.09RESR12-177.68 15.50 0.99 19.89 1.67 421 128 11 0.05RESR12-186.67 0.27 0.02 0.04 0.42 425 15 156 0.33RESR12-191.15 1.12 0.04 0.43 0.69 439 38 62 0.09RESR12-194.12 0.38 0.40 0.43 0.55 463 113 145 0.48RESR12-202.04 0.98 0.17 0.65 0.40 440 66 41 0.21RESR12-205.25 3.94 0.56 2.56 0.70 427 65 18 0.18RESR12-209.80 4.01 0.19 2.06 0.77 423 51 19 0.08RESR12-218.02 5.84 0.18 5.71 1.16 437 98 20 0.03RESR12-218.36 11.60 0.53 8.51 1.30 433 73 11 0.06RESR12-219.31 0.43 0.31 0.15 0.41 433 35 95 0.67RESR12-220.12 0.38 0.09 0.15 0.29 358 40 76 0.38


2 August 12, 2004





RESR8-11 1.62 0.11 3.42 0.80 443 211 49 0.03

ID

RESR12-221.20 2.02 0.55 4.73 0.60 441 234 30 0.10RESR12-222.5 0.39 0.05 0.09 0.11 445 23 28 0.36RESR12-233.58 0.47 0.13 1.06 0.09 439 256 29 0.11RESR12-234.59 1.84 0.42 3.73 0.40 442 203 22 0.10RESR12-235.19 1.97 0.20 3.04 0.55 439 154 28 0.06RESR12-235.55 2.62 0.41 6.70 0.61 442 256 23 0.06RESR12-236.0 4.51 1.23 14.87 0.59 442 330 13 0.08RESR12-236.33 3.98 0.42 9.42 0.74 442 237 19 0.04RESR12-236.65 1.65 0.20 5.64 0.51 443 342 31 0.03RESR12-236.95 3.99 0.47 11.43 0.62 440 287 16 0.04RESR12-237.19 13.00 1.05 19.20 1.04 430 148 8 0.05RESR12-237.30 5.65 0.53 13.36 1.76 437 237 31 0.04RESR12-239.36 0.99 0.17 0.47 0.20 460 48 20 0.27RESR12-240.64 0.98 0.16 0.36 0.53 430 37 54 0.31RESR12-241.42 1.51 0.13 0.55 0.60 444 36 40 0.19RESR12-244.16 0.51 0.22 0.18 0.16 333 35 31 0.55RESR12-247.08 0.46 0.09 0.21 0.09 340 46 20 0.30RESR12-247.38 0.80 0.08 0.46 0.23 438 58 29 0.15RESR12-247.70 0.71 0.19 0.49 0.40 437 69 56 0.28RESR12-248.08 0.64 0.12 0.51 0.39 443 80 61 0.19RESR12-248.48 0.59 0.14 0.40 0.28 437 68 48 0.26RESR12-248.82 1.00 0.35 0.84 0.16 436 84 16 0.29RESR12-249.16 0.80 0.41 0.54 0.31 438 68 39 0.43RESR12-249.52 1.35 0.15 0.97 0.13 438 72 22 0.13RESR12-249.87 1.34 0.16 1.09 0.52 440 81 39 0.13RESR12-250.22 2.25 0.17 2.72 0.64 440 121 28 0.06RESR12-250.5 2.04 0.13 2.26 0.23 437 111 11 0.05RESR12-250.90 2.72 0.27 2.68 0.72 438 99 27 0.09RESR12-251.28 3.49 0.40 4.49 0.68 438 129 20 0.08RESR12-251.65 1.66 0.22 1.31 0.91 436 79 55 0.14RESR12-251.88 2.31 0.34 6.34 0.05 441 275 45 0.05RESR12-252.31 41.10 4.56 55.34 2.56 440 135 6 0.08RESR12-257.33 2.90 0.15 2.09 0.16 438 72 6 0.07RESR12-257.95 0.50 0.18 0.30 0.07 440 60 14 0.38RESR12-258.78 0.33 0.03 0.07 0.58 315 21 176 0.30PH3-1385.9 2.27 0.12 0.68 1.06 421 30 47 0.15PH3-1398 0.73 0.39 0.36 0.78 450 49 107 0.52PH3-1425.4 0.72 0.47 0.33 0.89 435 46 124 0.59PH3-1431.3 0.65 0.12 0.61 0.55 441 94 85 0.16PH3-1434.6 4.18 0.19 3.27 0.32 441 78 8 0.05PH3-1515 0.39 0.09 0.07 0.49 436 18 126 0.56PH3-1601.8 0.41 0.45 0.15 0.42 433 37 102 0.75PH3-1605.3 0.47 0.45 0.16 0.20 436 34 43 0.74PH3-1608.6 1.60 0.64 1.23 0.06 439 77 4 0.34PH3-1617.8 0.51 0.09 0.31 0.33 442 61 65 0.23PH3-1621.1 0.26 0.08 0.02 0.38 543 8 146 0.80PH3-1622.9 0.24 0.03 0.07 0.33 544 29 138 0.30PH3-1637.8 1.08 0.11 0.66 0.22 440 61 20 0.14PH3-1674.9 0.44 0.06 0.67 0.74 452 152 168 0.08PH3-1678.2 1.30 0.32 0.86 1.94 443 66 149 0.27PH3-1683.8 0.34 0.06 0.02 0.19 435 6 56 0.75PH3-1708.7 0.26 0.05 0.06 0.08 455 23 31 0.45PH3-


3 August 12, 2004





RESR8-11 1.62 0.11 3.42 0.80 443 211 49 0.03

ID

PH3-1713.8 0.96 0.37 0.80 0.55 440 83 57 0.32PH3-1718.9 0.54 0.05 0.25 0.20 430 46 37 0.17PH3-1742 0.37 0.03 0.06 0.36 449 16 97 0.33PH3-1793 0.47 0.02 0.13 0.39 546 28 83 0.13PH3-1822 0.29 0.05 0.11 0.05 477 38 17 0.31PH3-1834.5 0.30 0.08 0.13 0.16 433 43 53 0.38PH3-1839.8 2.33 0.36 2.62 0.53 443 112 23 0.12PH3-1850.9 1.05 0.28 1.10 0.37 437 105 35 0.20PH3-1856.4 5.73 0.31 7.58 0.30 442 132 5 0.04PH3-1875.5 2.27 0.12 3.28 0.64 437 145 28 0.04PH3-1885.4 2.93 0.19 5.01 0.84 440 171 29 0.04PH3-1895.4 0.44 0.05 0.18 0.41 454 41 93 0.22PH3-1905.6 0.41 0.05 0.21 0.43 438 51 105 0.19PH3-1921.1 2.56 0.12 1.72 1.18 432 67 46 0.07PH3-1948.8 5.25 0.39 3.37 0.77 432 64 15 0.10PH3-1958.9 0.31 0.04 0.16 0.30 445 52 97 0.20PH3-1968.4 2.50 0.16 2.23 0.85 435 90 34 0.07PH3-2127.8 2.69 0.11 1.57 0.58 430 58 22 0.07PH3-2138 1.80 0.08 0.94 0.50 430 52 28 0.08PH3-2145.5 1.93 0.10 1.58 0.04 439 82 54 0.06PH3-2149.4 1.93 0.14 1.36 0.75 436 74 41 0.09PH3-2158.8 0.28 0.06 0.17 0.26 447 61 93 0.26PH3-2192.2 1.90 0.10 3.31 0.86 440 174 45 0.03PH3-2206.3 0.47 0.04 0.26 0.66 432 55 140 0.13PH3-2215 1.55 0.12 1.43 0.45 436 92 29 0.08PH3-2224.1 1.40 0.13 1.43 0.53 437 102 38 0.08PH3-2283.3 0.32 0.06 0.11 0.31 437 34 97 0.35PH3-2288.5 3.05 0.31 5.63 0.46 438 185 15 0.05PH3-2298.6 0.38 0.70 0.27 0.48 408 71 126 0.72PH3-2308.4 0.38 0.09 0.14 0.52 435 37 137 0.39PH3-2314.8 0.58 0.05 0.08 1.07 477 14 185 0.38PH3-2317.8 3.85 0.12 0.55 0.34 536 14 9 0.18PH3-2338.3 0.32 0.08 0.03 0.34 543 9 106 0.73PH3-2371.3 0.36 0.15 0.05 0.27 543 14 75 0.75PH3-2372.4 0.49 0.13 0.12 0.69 432 25 141 0.52PH3-2373.9 0.63 0.07 0.27 0.55 446 43 87 0.21PH3-2374.9 1.88 0.14 2.74 0.82 441 146 44 0.05PH3-2376.2 0.73 0.11 0.69 0.74 438 95 101 0.14PH3-2377.4 1.57 0.07 1.98 0.65 436 126 41 0.03PH3-2378.8 2.92 0.14 3.64 0.88 439 125 30 0.04PH3-2379.6 0.69 0.17 0.28 0.36 433 41 52 0.38PH3-2399.1 0.39 0.11 0.15 0.40 430 39 103 0.42PH3-2439.3 0.44 0.20 0.15 0.74 429 34 168 0.57PH3-2442 0.38 0.08 0.23 0.31 445 61 82 0.26PH3-2444.6 0.39 0.29 0.19 0.15 486 49 39 0.60PH3-2450 0.50 0.23 0.16 0.14 522 32 28 0.59PH3-2462.2 0.41 0.12 0.11 0.68 423 27 166 0.52PH3-2463.8 0.38 0.06 0.03 0.21 520 8 55 0.67PH3-2465.8 0.36 0.17 0.08 0.29 444 22 81 0.68PH3-2468.8 0.33 0.20 0.06 0.44 480 18 133 0.77PH3-2472 2.92 0.18 4.95 0.66 443 170 23 0.04PH3-2474.8 1.68 0.08 1.01 0.59 429 60 35 0.07PH3-2491.6 0.39 0.54 0.40 0.29 433 103 74 0.57


4 August 12, 2004





RESR8-11 1.62 0.11 3.42 0.80 443 211 49 0.03

ID

PH3-2496.5 1.53 0.16 0.69 0.25 440 45 16 0.19REMAC-001 1.23 0.20 2.03 0.84 439 165 68 0.08REMAC-002 1.87 0.09 2.24 0.43 440 120 23 0.04REMAC-003 2.70 0.14 3.96 0.75 439 147 28 0.03REMAC-004 2.80 0.13 4.20 1.01 435 150 36 0.03REMAC-005 2.63 0.11 4.24 0.77 435 161 39 0.03REMAC-006 2.41 0.19 4.03 0.53 436 167 22 0.05REMAC-007 3.13 0.17 5.12 0.97 437 164 31 0.03REMAC-008 2.83 0.16 3.88 1.03 437 137 36 0.04REMAC-009 1.79 0.05 1.62 2.13 438 91 119 0.03REMAC-010 2.46 0.08 3.04 1.55 437 124 63 0.03REMAC-011 2.21 0.13 2.75 0.79 440 124 36 0.05REMAC-012 2.95 0.08 5.44 0.78 435 184 26 0.01REMAC-013 2.75 0.10 3.49 0.58 436 127 21 0.03REMAC-014 0.64 0.03 0.08 0.19 441 13 30 0.27REMAC-015 1.56 0.10 1.12 1.69 435 72 108 0.08REMAC-016 0.93 0.09 0.32 0.27 423 34 29 0.22REMAC-017 1.95 0.17 1.23 0.48 434 63 25 0.12REMAC-019 2.75 0.13 5.68 1.22 437 207 44 0.02REMAC-018 2.66 0.09 4.35 0.49 438 164 18 0.02REMAC-020 1.72 0.07 2.83 2.47 434 165 144 0.02REMAC-021 2.92 0.14 5.06 1.13 440 173 39 0.03REMAC-022 2.60 0.09 4.92 0.79 438 189 30 0.02REMAC-023 2.47 0.13 4.57 0.79 440 185 32 0.03REMAC-024 1.21 0.04 0.76 0.75 428 63 62 0.05REMAC-025 2.66 0.09 4.78 1.10 438 180 41 0.02REMAC-026 3.01 0.10 5.25 0.56 440 174 19 0.02REMAC-027 1.77 0.06 3.52 1.93 434 199 109 0.02REMAC-028 2.56 0.11 6.66 0.68 441 260 27 0.02REMAC-029 1.81 0.28 3.32 1.20 439 183 66 0.08REMAC-030 1.01 0.07 1.19 0.76 436 118 75 0.06REMAC-031 1.35 0.13 1.80 0.86 437 133 64 0.07REMAC-032 3.21 0.23 9.23 1.30 439 288 41 0.02REMAC-033 3.47 0.20 6.34 1.62 435 183 47 0.03REMAC-034 2.17 0.12 3.52 3.25 441 162 150 0.03REMAC-035 3.36 0.26 7.17 0.66 440 213 20 0.04REMAC-036 2.22 0.14 4.55 0.67 441 205 30 0.03REMAC-037 2.90 0.14 5.24 0.98 442 181 34 0.03REMAC-038 0.71 0.04 0.61 0.34 435 86 48 0.06REMAC-039 1.14 0.10 0.93 0.47 429 82 41 0.10REMAC-040 1.60 0.11 2.63 2.26 437 164 141 0.04REMAC-041 1.53 0.17 2.62 0.68 441 171 44 0.06REMAC-042 2.46 0.15 2.93 1.62 437 119 66 0.05REMAC-043 0.89 0.14 1.19 0.48 431 134 54 0.11REMAC-044 2.34 0.12 4.30 0.65 442 184 28 0.03REMAC-045 2.87 0.17 5.79 1.85 435 202 66 0.03REMAC-046 2.17 0.14 4.24 0.95 437 195 44 0.03REMAC-047 1.80 0.15 3.56 1.03 440 198 57 0.04REMAC-048 3.46 0.26 6.06 1.20 436 175 35 0.04REMAC-049 2.23 0.19 4.33 1.26 438 194 57 0.04REMAC-050 4.93 0.23 10.45 1.24 435 212 25 0.02REMAC-051 2.89 0.22 5.01 1.21 442 173 42 0.04REMAC-052 2.06 0.22 2.87 2.78 436 139 135 0.07


5 August 12, 2004





RESR8-11 1.62 0.11 3.42 0.80 443 211 49 0.03

ID

REMAC-053 2.29 0.16 2.75 0.33 436 120 14 0.06


6 August 12, 2004

For: NSDOE A Pseudo-Van Krevelen Diagram(from Tammy Allen's Thesis)

Western Cape Subbasins(Colindale Member)

Kerogen type determination from TOC and Rock-Eval pyrolysis data. TypesI and II will generate oil, type III gas, and type IV little or no hydrocarbons.

0

100

200

300

400

500

600

700

800

900

0 50 100 150 200

OXYGEN INDEX (OI)

HYD

RO

GEN

IND

EX (H

I)

l

II

III

IV

From: Global Geoenergy Research Ltd.Appendix C-3b

1 August 3, 2004

Appendix C-4a. Location of oil-stain samples from the Horton Group of Lake Ainslie area that were used for geochemical analysis (from Fowler et al, 1993)

Appendix C-4b. Geochemical data of oil-stain sandstones of the Horton Group from the Lake Ainslie area (from Fowler et al, 1993)

Appendix C-5a. Location of reservoir samples from various wells from onshore and offshore Nova Scotia whose analytical data on porosity and permeability data have compiled (from Bibby and Shimeld, 2000)

Appendix C-5b. Various plots on porosity and permeability for reservoir samples of various wells from onshore and offshore Nova Scotia (from Bibby and Shimeld, 2000)

Documents

Contract No. 60122058 of March 31, 2004 Final Report ... · Final Report (Revised) Submitted to Paul J. Harvey Project Coordinator, Cape Breton Project Nova Scotia Department of Energy