Revised Exploration Model for the Inversion Fairway,
Western Port au Port Peninsula, Newfoundland
A report for Canadian Imperial Venture Corp.
St. John’s, Newfoundland
by
George S. Langdon, PhD, P.Geol.,
Tectonics, Inc., Calgary
and
Ray Mireault, P.Eng., Fekete Associates Inc., Calgary
June 4, 2002
(Note: This report was written before the ST-2 well was conceived.)
1
Executive Summary
The Port au Port #1-ST1 well was drilled as a sidetrack from the original Port au Port #1
well in the summer and fall of 2001. The well confirmed the existence of an updip
structure to the west, but within the upper Aguathuna Formation (oil-bearing at Port au
Port #1) encountered non-dolomitized tight limestone. Porous but low-permeability
dolomites were encountered in the lower Aguathuna Formation which flowed water on test
at Port au Port #1.
The Port au Port #1 discovery well has been tested over three time periods and has
produced some 3400 m3 (21400 barrels) of oil. Pressure, production and operational
history supports the hypothesis of a large oil accumulation at Garden Hill South. The
reservoir is considered to comprise two components: a low permeability matrix
component, and a high permeability cavernous/paleokarst component. Due to well control
problems during drilling, both of these are thought to be heavily invaded, which may in
whole or in part explain the behaviour of the matrix as a low-permeability reservoir in the
immediate vicinity of the borehole.
The interpretation of a stratigraphic-diagenetic trap has led to a reassessment of the play
concept and the recognition of the importance of regional faults as the likely major control
on porosity and permeability. Along such fault trends, hydrothermal dolomitization
enhances pre-existing porosity and permeability controlled by facies, burial dolomitization
and karst processes, the latter of which may also be directly related to fault trends. The
Round Head Thrust fault, which bounds the eastern edge of the inversion fairway and
trends for some 30 km on the Port au Port Peninsula, is thought to be the main control on
dolomitization, and may represent a continuous belt of stratigraphically-trapped potential.
The Garden Hill North prospect lies within the projected dolomitized belt and is still
mapped as a structural (domal) prospect.
2
The next well, Port au Port #2, is proposed to follow this trend ~400 m NNE of the
productive Port au Port #1 well, taking advantage of approximately 20 m of structural gain
across a minor tear fault.
Two analogues illustrating important fracture-controlled reservoirs, Albion-Scipio (300
mm BOIP) and Ladyfern (300 BCF –1 TCF), are reviewed.
Because the boundaries of the Garden Hill South field cannot be mapped at this point,
reserves cannot be assigned, and a speculative potential of 100 mmbo recoverable is
estimated, based on all available information and analogues. Adding this to the 100 – 300
mmbo potential for the structural Garden Hill North prospect, regional speculative
potential for the inversion fairway is estimated at 200 – 400 mmbo recoverable.
If the salt water seen at the base of the productive zone in Port au Port #1 is not a fluid
contact, but perched karst water, the possibility exists that the oil leg in the upper
Aguathuna extends downdip in three directions from the well. This, along with the
possibility of deeper oil-water contacts in compartmentalized sections of the field further
northeast along the fairway, could result in a very large upside potential, comparable to
that seen in analogue fields.
3
List of Figures, Plates and Attachments
(Please Note: The Figures have reduced resolution to minimize file size for downloading
purposes and may not be suitable for printing.)
Figure 1: Regional map of inversion fairway, showing projected reservoir edge interpreted
from drilling results.
Figure 2: Structure map in depth and dolomitization edge, Garden Hill South and southern
inversion fairway.
Figure 3: Schematic dip profile across the Garden Hill South field, showing reservoir
geometry and well trajectories.
Figure 4: Seismic line CAH-93-5, showing erosion of top of fault block near the Round
Head Thrust.
Figure 5: Log cross-section across the platform section, PP#1-ST1 to PP#1. Datum: sea
level.
Figure 6: Cross-sectional model of karsting and dolomitization for the inversion fairway.
Figure 7: Map of the Albion-Scipio field, Michigan Basin.
Figure 8: Block diagram and cross-section through the Albion-Scipio field, showing
relationship between dolomitization, reservoir development and faulting.
Figure 9: Map and profile through Ladyfern gas field, northeastern British Columbia.
Figure 10: Schematic profile showing potential NNE along fairway and Port au Port #2
location relative to Port au Port #1.
4
Figure 11: Cross section of well location for Port au Port #2.
Plates 1 – 4: Photomicrographs of cuttings from lower Aguathuna reservoir, Port au Port
#1-ST1.
Appendix I: Well pressure and production history, Port au Port #1.
5
Contents
Introduction
Results: Port au Port #1
Results: Port au Port #1-ST1
Interpretation and Discussion of Results
Implications for the Garden Hill Fairway
Analogues: Albion-Scipio and Ladyfern
Conclusions and Recommendations
Speculative Potential
References
Figures
Plates
Appendix I
6
Introduction
Recent drilling and abandonment of the Port au Port #1-ST1 well has resulted in the need
to revise the exploration model for the inversion fairway on the Port au Port Peninsula.
This model was developed and discussed in a series of internal reports between 1999 and
2001 by Tectonics, Inc. and Tectonics/Fekete Associates (see References).
Other
references document the general technical aspects of the western Port au Port play. The
present report is intended as a post-mortem to the recent drilling at Garden Hill South, and
as a guide for future exploration of the inversion fairway between Garden Hill South and
North (Figure 1).
Results: Port au Port #1
The 1995 discovery of oil in the Upper Aguathuna Formation by the Hunt/PCP Port au
Port #1 well was remarkable because an oil discovery on the first drilling attempt is
improbable at the best of times. . It was even more unusual at Port au Port because the
well was drilled as a stratigraphic test and was the first deep exploratory well in the
Western Newfoundland basin.
Statistically, there is only a remote chance that an almost randomly selected well location
could have encountered oil in an isolated accumulation on the southwest side of a small
tear fault. Based on the well history and the available geological evidence, it is much more
likely that the well encountered a large, areally extensive reservoir. This was the first of a
series of indicators that supported drilling a stepout well.
The well pressure and production history also suggested that PaP #1 encountered a large
oil accumulation in a dual porosity, low permeability formation (Attachment _). Well PaP
#1 has been tested over 3 time periods:
1. From April to July 1995, Hunt Oil produced 1372 m3 of oil from a series of cased
hole DST’s on the Upper Aguathuna Formation.
7
2. From May to June 2000, CIVC produced 320 m3 of Upper Aguathuna oil.
3. From May to June 2001 CIVC produced an additional 1722 m3 of Aguathuna oil.
Following the 1995 test period, the well was shut in for 5 years. Although there is some
uncertainty in the discovery pressure for the pool, it appears that reservoir pressure
essentially returned to its discovery value at some time during the shut in period. A static
gradient bottomhole pressure after 5 years was 37,857 kPaa compared with an estimated
discovery pressure of 37,800 kPaa1.
A post-production buildup back to the original
pressure infers a significant oil accumulation.
Early in the production life of a reservoir, material balance techniques provide only a
minimum oil-in-place value and are generally considered unreliable until at least 5% of the
true oil-in-place has been produced. In low permeability reservoirs, the calculated value
can be orders of magnitude less than the true oil-in-place, due to the difficulty in
estimating reservoir pressure and the extreme sensitivity of the calculation to pressure error
in the early stages of depletion. A heterogeneous fluid distribution at Port au Port creates
additional difficulty for the technique.
PaP #1 built up pressure for a year following the 2000 production period. The May 2001
static gradient presssure of 34800 kPa suggests a pressure buildup rate of about 2000
kPa/year and confirms that a low permeability reservoir exists in the area penetrated by the
well.
Although matrix permeability is low around the PaP #1 well, there are both
geological and mechanical reasons for expecting that matrix permeability could improve
significantly in other areas of the reservoir.
Anecdotal evidence2 that is not in the well tour reports suggests that large volumes of mine
tailings plus front end loader buckets of peat bog may have been pumped down the
wellbore in an effort to regain circulation. The tour reports confirm that weeks were spent
1
Uncertainty in the initial pressure estimate creates the discrepancy between the pressure values.
Conversations with local residents suggest that 1 to 3 mining trucks may have transported mine tailings to
site from a local dolomite/limestone mine. There is no evidence of surface use at the wellsite. The use of a
front end loader to collect peat bog for injection down the wellbore comes from an individual who claimed to
have been a driller on the PaP#1 well.
2
8
trying to regain circulation after a karst of 0.5 meters height was penetrated in the Upper
Aguathuna interval.
The “dump truck” and front end loader volumes are in addition to the thousands of pounds
of lost circulation material that was reported to have been pumped down the well. If this
staggering amount (literally tons) of material was truly pumped down the well, it would
have massively invaded the formation karst and matrix to well beyond the limits of what is
usually thought of as wellbore damage. With a sufficiently invaded matrix, the pressure
response accordingly behaves as a zone of low permeability.
The March 2002 static gradient presents an interesting behavior that may hint at the
validity of the story. Production from May to June 2001 created less of a pressure drop
and/or a faster post-production pressure buildup rate than was observed during the first two
production periods. The phenomenon is usually explained by the development of a free
gas saturation in the reservoir and is accompanied by an increase in the producing gas-oil
ratio (GOR) during production. However, the producing GOR appeared constant during
the test period. In addition, the produced volume should not have been sufficient, based on
previous performance, to deplete the reservoir enough to develop a free gas saturation.
The data creates two options. Either:

PaP #1 was produced just long enough to create a free gas saturation in the
reservoir that altered the system compressibility, but shut in before the free gas
saturation increased sufficiently to became mobile and affect the producing
GOR.

The performance improvement is at least partly attributable to matrix cleanup
with production. Perforating an additional 7 metres of matrix, as was done in
May 2001, can account for improvements in short term performance but does
not explain the improvement in the year-long shut in pressure buildup trend.
9
The former explanation cannot be ruled out but is coincidental, as the required production
volume is unknown. The latter explanation is unorthodox, but appears to satisfy the
known data.
While pressure, production and operational history supports the hypothesis of a large oil
accumulation at Port au Port and offers some potential, independent of geology, for
improved formation permeability in other areas of the reservoir, it cannot provide any
insight on reservoir geometry.
The task of selecting the stepout location fell to the
geological model and the seismic interpretation, which were the tools used to locate well
PaP#1-ST1.
Results: Port au Port #1-ST1
The well, the first operated by Canadian Imperial Venture Corp. (“CIVC”), was the
earning well for the farmin agreement between CIVC and Hunt/PCP. Under the terms of
the agreement, CIVC has now earned a 100% W.I. in the Port au Port #1 (1995) borehole,
subject to a 10% royalty, and a 50% W.I. in the development lands awarded by the
Government of Newfoundland under the development plan approved on November 15,
2001. To earn this interest, CIVC assumed 100% of the cost of the Port au Port #1-ST1
well.
The well was spudded on August 17, 2001 and abandoned on December 17, 2001, after
117 days on location. It was drilled as a whipstock out of the Hunt/PCP Port au Port #1
borehole. Prior to setting of the whipstock, a Baker Hughes ML packer, designed to allow
subsequent multi-lateral completions, was set beneath the whipstock and above the
productive Aguathuna zone. The whipstock was set at 2343 m, 165 m above the 9
5/8”casing shoe at 2508 m, and oriented toward azimuth 278 to test the Aguathuna in an
updip position (Figure 2).
8 ½” hole was deviated successfully from the whipstock and drilling proceeded in the
Winterhouse Formation below the Round Head Thrust (RHT; Figure 3). Formation tops in
10
the foreland basin succession (Lourdes, Goose Tickle and Table Cove), came in close to
prognosis, and 7” casing was successfully set at 3493 m in the Table Point Formation,
aided by the use of a MWD gamma ray tool run approximately 4 m behind the bit. Drilling
of this initial section to casing point took 42 days.
After drilling out, 6” hole was drilled ahead in tight limestone, and did not encounter the
upper Aguathuna porous dolomite zone seen in Port au Port #1. This section, originally
interpreted by the wellsite geologist as Table Point lithology, continued to a depth of 3502
m TVD, where porous dolomite was finally encountered (Figures 3 and 5). Below this
point, the well drilled in dolomite to the top of the Costa Bay Member at 3541 m TVD.
Several porous dolomite zones with mud gas shows, up to several hundred units, and oil
staining in samples were encountered in this interval. The Costa Bay was mainly tight
dolomite down to the top of the Catoche Fm. at 3564.8 m TVD. Drilling then continued to
the tight limestone of the Catoche Formation, whereupon the hole was logged and DST #1
was carried out. The test interval was set from bottom hole to the 7” casing. The test
recovered a small amount of oil in the mud and was interpreted as testing a zone of very
low permeability.
At this point pressure testing revealed leakage above the whipstock in the original
borehole, and it was found that several joints of the original 9 5/8” casing had parted at
around 900 m. The repair and reconditioning operation took place over a period of 47
days.
The well was subsequently drilled to a total depth of 3951.7m TVD ( measured depth
4053.5 m) in the Berry Head Member (Petit Jardin Formation, Port au Port Group). No
significant porosity or shows were encountered in the Boat Harbour or Watt’s Bight
Formations, although these rocks were almost entirely dolomitized. Most notable was the
absence of karst in the Watts Bight Formation, although a thin (2.5 m over 9 m gross) zone
of karst-filling sulphide mineralization, equivalent to the upper karst zone in the Watt’s
Bight in Port au Port #1, was drilled.
11
Interpretation and Discussion of Results
The results of the ST1 well have necessitated a rethinking of the exploration and
development model with respect to the inversion fairway of the Port au Port Peninsula. To
discuss this new exploration concept, it is useful to step back and review the initial
exploration model and the rationale for drilling Port au Port #1-ST1, as described in reports
by Tectonics, Inc. (1999 - 2000).
The seismic program which was acquired and interpreted in the summer and fall of 2000
led to the identification of a large structure in the footwall shortcut fault block of the
Round Head Thrust. Based on the interpretation of downdip seismic line CAH-93-5
(Figure 4), this structure displayed the geometry of a rollover anticline. The new onshore
dataset across the structure showed monoclinically east-dipping beds which were
interpeted to image the east flank of the large anticline, the west flank of which is entirely
offshore (Figure 2). Mapping of the structure through the onshore data set enabled the
definition of 3-way closure, with the 4th closure direction implied by the hydrocarbon
accumulation.
This relatively straightforward structural picture was then combined with information from
the wellbore, most notably, an interpretation of an oil-water contact in the lower karst zone
at –3251 m, to develop an integrated interpretation of a structurally-controlled oil field
lying almost entirely updip of Port au Port #1. Speculative reserves were assigned to the
field based on an assumption of reservoir continuity across the structural trap. As the
petroleum system had already been proven by the results of Port au Port #1, reservoir
continuity represented the main risk in the prospect. Given the early stage of drilling of the
Garden Hill fairway, this risk was considered acceptable in light of the prospect potential.
The sidetracked well encountered tight, non-dolomitized, non-porous limestone in the
upper Aguathuna (roughly equivalent to the Spring Inlet Member) and 12.5 m of porous
12
but tight dolomite over a gross interval of 38 m in the lower Aguathuna/Costa Bay section
(these are the author’s informal stratigraphic terms and are illustrated on Figure 5). The
upper 9 m of this net pay were tested in DST#1. This latter zone can be correlated with the
zone that flowed 1100 BWPD in Port au Port #1, indicating that over a distance of about
350 m a dramatic loss of permeability has occurred. The identification of oil on logs and
the recovery of a small amount of oil on test represent the first known oil in the lower
Aguathuna. The presence of this oil both structurally and stratigraphically lower than the
oil in the upper Aguathuna at Port au Port #1 is significant and establishes new potential
for this zone in the play fairway.
The results of the drilling of the Aguathuna/Costa Bay Member establish that Aguathuna
oil in Garden Hill South is held in place by a hybrid trapping configuration which
combines structural tilt and reservoir discontinuity. Furthermore, as illustrated in Figures 2
and 5, the presence of oil in ST1 that is structurally lower than water in the lower
Aguathuna in PP#1 (as interpreted from logs) implies that these two zones are
hydrodynamically separated, either by (1) presence of tight units or beds separating porous
units within the upper part of the lower Aguathuna, i.e., the section above DST #2 in Port
au Port #1, or (2) a sub-vertical structural discontinuity such as a fault or fracture system
between the two wells. It may indicate a Carboniferous-age fracture system with a small
amount of horizontal offset and no vertical offset, such as has been mapped in the field by
I. Knight (pers. comm., 2001) and others on the central Port au Port Peninsula, within the
hangingwall of the Round Head Thrust.
The lower Aguathuna porous rock over the interval 3555-3600 m (MD) was studied for
reservoir information (Fekete/Brandley Rock Research, December 2001). The study was
designed to address the following questions:
1. What is the lithology and reservoir character of the rock?
2. What is the production potential?
3. How will the rocks respond to acid treatment?
4. Why is there obvious log porosity but no production as indicated?
13
The results of the rock study establish that reservoir quality rock was penetrated in the
well. The reservoir can be divided into an upper porous zone (comprising 3 intervals
between 3502-3516 m TVD), and a lower porous zone (3525-3533m TVD; Figure 5).
The upper porous zone is classified as a matrix reservoir (porosity and permeability are
determined solely by matrix pores). It is a dark brown, earthy (10-40 micron) dolostone
which is partly calcareous and oil-stained throughout (Plate 1). Average estimated
intercrystalline porosity is 6.8%, with a maximum at 10%, and average estimated
permeability is 2.4 md. Upon placing chips from this interval in a cold acid bath (10%
HCl) for 3 minutes, the sample disaggregates into a mass of residual dolomite crystals
(Plate 2), suggesting calcite cement.
The intervening non-reservoir zones in the upper interval comprise dense, crypto- to
microcrystalline dolo-mudstone, with 0% porosity and no permeability.
The lower porous zone is classified as a small pore reservoir (porosity contribution from
both matrix and small non-touching pores, but permeability contribution only from the
matrix). Calcite in the sample stains red in Alizarin Red S, and is estimated to constitute
around 10% of the cement. The rock is white crystalline (90-125 micron rhombs)
dolostone (Plates 3 and 4). The zone is interpreted to have a streaky distribution of porous
rock, probably on a centimeter to decimeter scale. Average estimated porosity is 5.3% and
average estimated permeability is 2.2 md. As in the upper zone, disaggregation occurs
upon placing samples in a cold acid bath. Rare oil and pyrobitumen staining are present.
The coarser dolomite in this lower zone is considered to be hydrothermal in origin.
Formation damage was also assessed from the cuttings analysis and it was concluded that
damage was very minimal, and would not have contributed to the DST results. Resident
fluid analysis suggests that the lower zone is a zone of mixed (oil and water) wetting, or a
transition zone. The upper porous zone is considered oil bearing.
14
Qualitatively, the ST1 borehole can be considered to have penetrated the reservoir at its
updip trapping edge, and hence the potential reservoir rock that was encountered lies in the
gradational zone between permeable and impermeable rock, as illustrated in Figure 5. Such
a zone is often referred to as a reservoir “waste” zone, and in this case it appears to be
characterized by the occlusion of porosity and choking of pore throats by late stage calcite
cement.
An acid frac was considered for the tested zone, but was ruled out because it was thought
that (1) although some production would be obtained, only a massive, costly frac would
deliver production at commercial rates, and (2) there was a risk with a larger frac of
connecting to water which flowed on test in the equivalent zone in PP#1, approximately
350 m to the east.
The absence of karst in the Watt’s Bight Formation, and of porosity in the Boat Harbour
and Watts Bight Formation in general may suggest that reservoir quality is related to
paleostructure and distance from the Round Head Thrust.
This characterization of an oil-bearing lower Aguathuna is very significant, because, when
combined with the DST results noted above for the lower Aguathuna in Port au Port #1
(1100 barrels of water per day), the opportunity to discover a highly productive oil
reservoir along the trend of the fairway is brought into focus.
Implications for the Garden Hill Fairway
The results of the Port au Port #1-ST1 well evidently necessitate a re-evaluation of the play
model for the whole of the Garden Hill inversion fairway play. Several key questions must
now be addressed prior to further drilling in the area.

What is the nature of and major control on reservoir quality?
15

Can reservoir quality be predicted by an understanding of paleostructure in the
inversion fairway, i.e., in the shortcut footwall to the Round Head Thrust?

How do reservoir and structure combine to provide trapping mechanisms?
The drilling of the ST1 well has provided much information about the nature of the
trapping within the Aguathuna Formation. Both the upper and lower Aguathuna are
characterized by a loss of porosity and permeability westward away from the Round Head
Thrust. This loss is attributed to a sharp dolomitization front which has analogues at the
surface in western Newfoundland. Near Port au Choix on the Great Northern Peninsula,
very sharp dolomitization fronts are observed in equivalent platform rocks in the field.
Across such fronts, a change from fine-grained limestones to sucrosic, pervasive dolomites
over a distance of <1 m occurs, at least at the macroscopic scale. Such a change may occur
between the two Garden Hill south wells. On a microscopic level, the transition may be
more gradual and complex, as suggested by the presence of good but ineffective porosity
and of a petrological transition zone in the lower Aguathuna in ST1.
The dolomitization front at Garden Hill South appears to be sloping westward, as reservoir
quality also changes downward from non-porous, impermeable limestone in the upper
Aguathuna to porous, impermeable dolomite in the lower Aguathuna. The significance of
this geometry is unclear, i.e., it is unknown whether or not the dolomitization affects lower
units such as the Catoche in a westward direction (Figure 3).
With regard to the Boat Harbour and Watts Bight Formations, increasing distance from the
Round Head Thrust appears to have resulted in an almost total absence of karsting and a
concomitant decrease in porosity and permeability in dolomitized rock. This observation
suggests that pervasive dolomitization may be intimately related to karsting in these
formations.
16
A model has been discussed in earlier published and unpublished literature that partially
addresses the issue of porosity development in the inversion fairway. Geologists at Hunt
Oil developed a series of cross-sectional reconstructions which illustrated the evolution of
porosity as related to the development of the St. George Unconformity and the Round
Head Thrust. This model has been modified in Figure 6 to reflect the results of ST1.
Porosity development in the St. George Group is of two types: (1) matrix dolomite, and
(2) paleokarst. It now appears that both these types of porosity are related to proximity to
the Round Head Thrust, through the following mechanisms:
(1) karsting may be localized on the paleostructural highs at the eastern edges of rotated
fault blocks, where exposure at St. George Unconformity time was caused by regional
sea level drop and extensional tectonism, both likely related to the development of a
peripheral bulge caused by outboard loading of the advancing Humber Arm
Allochthon.
(2) early burial dolomitization exploited the open cavern systems and allowed for early
growth of some fairly coarse and sucrosic dolomite. Later Acadian-age hydrothermal
dolomitization, probably strongly focussed along the major inverting fault system, the
Round Head Thrust, moved laterally into beds with pre-existing permeability, either
through paleokarsting or an earlier stage of dolomitization.
As illustrated in Figure 6, these two components of the porosity system are related spatially
to the Round Head Thrust in the sense that erosional downcutting on the footwall blocks is
most intense immediately adjacent to the Round Head Thrust, as this area also represents
the most amount of uplift on the upthrown footwall of the pre-inversion (pre-Round Head
Thrust) Taconic basin. This bevelling is visible on seismic Line CAH-93-5 (Figure 4).
With these relationships in mind, a new exploration model for the play fairway can be
developed. Following the above arguments, porosity development in the Port au Port lands
may be more clearly linked to the Round Head Thrust than previously recognized.
17
If the oil leg at Port au Port #1 represents a minimum, based on the observation that
perched water in paleokarst, and not an oil/water contact, is present in the well, then the
Aguathuna oil may extend downdip in the direction of both the Round Head Thrust and the
northern continuation of the fairway. At this time, the extent of the oil cannot be
ascertained. The projection, and the recognition that the upper Aguathuna oil is
stratigraphically trapped, suggests a band of prospective reservoir that parallels the Round
Head Thrust along its western side. The width of this prospective zone can be derived to
first order from the results of the two wells. If the trapping edge is placed at the ST1 well,
it can be drawn approximately 5 km east of the Round Head Thrust. Maintaining this
distance, such an edge continued north along the fairway would include virtually all the
fairway lands as having potential for reservoir development (Figures 1, 2 and 6).
The following observations can now be made on Figures 1 and 2:
(1) Garden Hill South contains stratigraphically- (or more precisely, diagenetically-)
trapped oil by virtue of the widening of the fairway, and the combination of two critical
factors: the dolomitization edge and the east-dipping structure. The downdip limit of
the oil is not known at present.
(2) The intersection of the base-known-oil line derived from Port au Port #1 with the
dolomitization front determines an area which represents a minimum estimate of the
areal size of the accumulation.
(3) Further north along the fairway, the dolomitization front, if projected parallel to the
Round Head Thrust, would not lie in the east limb of the anticlinal structure and,
therefore, a stratigraphic-diagenetic trap would not be formed. The maximum extent of
this trap is defined by the relationship between the dolomization front and the timestructure contours, as shown in Figure 2.
(4) Because of the narrowing of the fairway northward, the prospectivity in its northern
part will rely primarily on structural closure, such as is mapped at Garden Hill North
(Figure 1). This structure should, under this scenario, contain completely dolomitized
Aguathuna Formation. In fact, the projection of a swath of reservoir development is
18
(5) the optimum condition for prospectivity in the structural prospect at Garden Hill North.
An alternative case would entertain the idea that the reservoir edge is not parallel or subparallel to the Round Head Thrust. In such a case the potential for stratigraphic trapping
would exist northward along the fairway, but this situation would depart from known
analogues and would be very difficult to predict.
Analogues
Analogues for the area, invoking a model of karsting and multi-stage dolomitization as
experienced in the Texas Ellenberger, have been presented in previous reports (see
References). Many aspects of these analogues still apply to the St. George Group reservoir
rocks. It is now clear that further control on reservoir geometry must be assessed in part by
consideration of other analogues, all of which may be thought of as partial analogues by
virtue their contribution to what now should be known as the “St. George model”.
Albion-Scipio
The Albion-Scipio giant field in the southern Michigan Basin (Figure 7) has unique
characteristics which provide insight into the nature of the Garden Hill South
accumulation. It is in fact, one of the world’s classic examples of a fracture-controlled
dolomite reservoir.
Albion-Scipio is developed within a dolomitized limestone sequence, the Middle
Ordovician Trenton and Black River Groups which are roughly time-equivalent to the
Table Head Group of western Newfoundland (Figure 8). The protolith of these groups is
dense limestone, but the sequence has been altered to a fairway of vuggy, fractured and
cavernous dolomite. The cavernous porosity in this case is totally attributed to solutions
associated with vertical and subvertical fractures, and not to karsting, but many of the
19
effects on drilling and production seen in the Ellenburger and St. George dolomites are the
same. The Albion-Scipio complex covers some 58 km2 (14,500 ac) and held an OOIP of
290 mmbo. A nearby, smaller field, Stoney Point, has a similar genesis.
Hundreds of wells have been drilled in the Albion-Scipio field (961 as of 1986; Hurley
and Budros, 1990), providing excellent insight into the nature of reservoir development
within fracture-controlled dolomite. This dolomite is developed within the Trenton-Black
River along a fracture system formed by minor strike-slip movement along a reactivated,
high angle basement fault. Although the tectonic regime and fault genesis are different than
that of the Garden Hill fairway, the effects on tight limestone sequences of the circulation
of hydrothermal fluids along fractures and faults are taken to be similar.
Some of the striking aspects of Albion-Scipio field geometry are (Figures 7 and 8):
(1) the dolomitization is developed evenly along the linear fracture system producing a
field which is 50 km long by a maximum 1.6 km wide.
(2) dolomitizing fluids appear to have moved uniformly away from the fault system
forming a reservoir edge which remains equidistant from the fault along its trend.
(3) a sharp contact exists between productive dolomite and non-productive regional
limestone. The transition can occur within a distance of a few hundred feet.
In the inversion fairway, the Round Head Thrust was the most important fault in the area
and was a conduit for hydrothermal fluid circulation (e.g., Cooper et al., 2001). In the
scenario presented here, fluids migrating into the platform section from the Round Head
Thrust would have been only able to move laterally in one direction, westward and updip,
as tight basement rocks were brought into juxtaposition on the eastern side of the fault. As
a first-order exploration model, and following the Albion-Scipio partial analogue, it is
proposed that the Upper Aguathuna dolomitization edge is developed uniformly along the
Garden Hill fairway west of the Round Head Thrust. Based on the results of the two wells,
this fairway is estimated to average 5 km in width, as illustrated in Figure 6.
20
Ladyfern
In 2000 a major Slave Point gas field was discovered at Ladyfern in northeastern British
Columbia (Figure 9). The initial well was completed with a reservoir pressure of 4400 psi
and a deliverablility of 100 mmcf/d. Subsequent drilling has established that the Ladyfern
gas field is areally extensive, covering up to 100 km2 in area, has a gas column greater than
100 m, proven recoverable reserves of 300 BCF and possible in-place reserves of up to 1
tcf.
The Ladyfern reservoir is a leached, fractured and hydrothermally dolomitized limestone.
Porosity development has been diagenetically enhanced along zones of extensional faulting
that parallel and crosscut the carbonate bank (Boreen et al., 2001). The trap can be
described as stratigraphic/diagenetic, but relies on a late-stage, porosity-creating episode of
dissolution, hydrothermal dolomitization, brecciation and fracturing. Aggressive leaching
of carbonate has created reservoir rock that is so porous locally that it crumbles easily in
the hand, with fracture and vuggy porosities up to 30%. Associated permeabilities range to
hundreds of millidarcies to darcies. Wells with limestone as reservoir have deliverabilities
in the range 1-20 mmcf/d, whereas wells in dolomitized reservoir (“monster wells”) can
produce at rates of 40-100 mmcf/d.
The importance of the Ladyfern analogue for the Garden Hill fairway lies in the fact that
both are characterized by porosity enhancement caused by fault-related late hydrothermal
dolomitization. In profile, like the Albion-Scipio model, the diagenetic-dolomitization
edge tends to be subvertical and roughly symmetrical about the fracture system (Figure 9).
Such edges provide an excellent model for the reservoir edge seen in recent drilling at
Garden Hill South.
It should also be noted from Figure 9 that several other fields in this play contain reserves
in the 0.5 tcf range.
21
Summary and Recommendations
The western Port au Port inversion fairway is a complex system of dolomitization that
likely combines aspects of several Ordovician platform carbonate play types, including the
karst-related dolomitization of the Ellenburger in Texas, the fold and thrust-related trap
geometries of the Arbuckle in Oklahoma, and the fault-controlled hydrothermal
dolomitization of Albion-Scipio in the Michigan Basin and Ladyfern in northeastern
British Columbia. Major reserves in giant fields are found in all these areas (commonly in
the range of several 108 barrels OOIP). The accumulation at Garden Hill South occurs in a
hybrid stratigraphic-structural trap formed by a sharp dolomitization front across a fold
limb.
Because the hydrocarbon accumulation is not strictly structurally controlled, exploration
programs in the inversion fairway must include provision for multiple well drilling, as the
seismic method may not be as useful in defining targets as in other areas where structural
targets can be pinpointed. Cost efficiencies should include multiple wells from existing
pads to fully assess the play from the exploration standpoint, as is the design at the
currently operational Port au Port #1/#2/#3 site.
A cross-sectional sketch (Figure 10) oriented subparallel to the fairway illustrates the
position of the proposed Port au Port #2 location with respect to Port au Port #1 and the
geometry of the reservoir and structure. Several potential discovery cases are presented
here (Figure 3):
1. “Base-known-oil’ case: If the 7 metre –thick limestone unit beneath the oil zone in Port
au Port #1 is an aquitard, the base oil in the well may not be an oil-water contact, as
water production is supersaline and may be perched karst water. This contact is
therefore shown on maps and cross-sections here as “base-known-oil”. This scenario
presents the possibility of downdip oil both southwest and northeast of the wells, the
upside of which cannot be accurately calculated at this time. The ultimate upside of this
case may be represented by the khaki-coloured area on Figure 2, which represents the
22
closure above a northeast-plunging structural nose, the western side of which would be
sealed by the dolomitization edge. A rough estimate of 100 mmbo recoverable is
assigned to this area.
This case also presents potential for new oil in the lower Aguathuna section, the lower
contact of which is unknown but would likely be higher than –3251, unless the tear
fault is a sealing fault (see Case 3 below). The discovery of such oil in ST1 suggests
that a charging mechanism is indeed present.
2. Oil-water contact case: if a true oil-water contact is seen in the well, than the oil-water
contact for both the upper and lower Aguathuna would be at –3251, and the lower
Aguathuna would likely be charged where it lies structurally above this depth.
3. Sealing fault case: if the east-west fault is a sealing fault, then fluid contacts from PP#1
cannot be projected, and the potential of the structure is unknown. While this presents
more uncertainty, it also provides the possibility of a very large upside (perhaps in the
range of several hundred million barrels) if a significantly lower fluid contact were
encountered. Regional geological considerations and the absence of oil in the A-36
well offshore to the southwest suggest that migration occurred from the northeast to
southwest along the fairway. Also significant is the fact that PP#1 oil has been
genetically linked to source rocks within the Humber Arm Allochthon, which outcrops
in the footwall area of the northern fairway.
It is recommended that the next well (Port au Port #2) be drilled at a location
approximately 400 m NNE of the Port au Port #1 borehole (intersection of seismic lines
CAH93-4A and CIVC Line 3), to test the Aguathuna reservoir. A well in this direction will
see a gain in structure of about 20 m across a minor tear fault and will parallel the Round
Head Thrust, which is proposed as the major control on reservoir development. Reservoir
quality equal to, or better than, that seen in the Aguathuna Formation in Port au Port #1 is
predicted.
23
A prognosis and drilling program for the Port au Port #2 well is in preparation under
separate cover.
Speculative Potential
The above discussion illustrates the difficulty associated with projecting reserves for
stratigraphically-trapped oil volumes. However, reasonable attempts can be made to
outline the speculative potential based on available information.
Using the Case 1 projected area (Figure 2), the original structural prospect range of 76-130
mmbo, and drawing from the analogues presented above, a speculative potential of 100
mmbo is assigned to Garden Hill South. The uncertainties are balanced by the additional
upside discussed in Case 3 above. The possibility for discovery of a major pool in the
order of several hundred million barrels of recoverable oil does exist.
Because Garden Hill North is still considered a structural prospect, former reserve
estimates of 100-300 mmbo recoverable are maintained. These numbers combined
produce a range for the entire fairway of 200-400 mmbo recoverable.
24
References
Boreen, T., et al., 2001: Ladyfern, Norteastern British Columbia: Major Gas Discovery in
the Devonian Slave Point Formation. Canadian Society of Petroleum Geologists Annual
Convention, 2001, Proceedings of the Core Conference.
Cooper, M., et al., 2001: Basin Evolution in Western Newfoundland: New Insights from
Hydrocarbon Exploration. American Assoc. of Petroleum Geologists, March 2001
Fekete Associates Inc., November 9, 2001: Garden Hill South Development, Port au Port
#1 well, May 20 to June 14, 2001 Production Test. Memo to partner Hunt Oil Company of
Canada.
Fekete Associates Inc. and Brandley Rock Research, December, 2001: Port au Port #1ST#1, West Newfoundland: Reservoir Quality Evaluation. Internal report.
Tectonics, Inc., October 22, 1999: Geological Conditions Pertaining to Proposed
Development of the Port au Port Oilfield, West Newfoundland. Internal report for
Canadian Imperial Venture Corp.
Tectonics, Inc., October 1, 2000: Report on Interpretation of Garden Hill Seismic Data.
Internal report for Canadian Imperial Venture Corp.
Tectonics, Inc., December 2000: Notes on Reservoir Quality and Continuity in the St.
George Group, Garden Hill Field: Effects of Paleokarst and Dolomitization. Internal
report for Canadian Imperial Venture Corp.
Tectonics, Inc., 2001: Contribution to: Geology, Development Plan Document (Canadian
Imperial Venture Corp.) for, Garden Hill South Oilfield, Port au Port Peninsula.
Tectonics, Inc., January 16, 2001: Petroleum Potential of the Garden Hill North Prospect,
Port au Port Peninsula, Newfoundland. Internal report for Canadian Imperial Venture
Corp.
Tectonics, Inc. and Fekete Associates Inc., July 9, 2001: Characterization of
Reservoir/Trap Geometries in the Inversion Fairway of the Round Head Thrust, Western
Port au Port Peninsula. Internal report for Canadian Imperial Venture Corp.
Tectonics, Inc., September? 2001: Garden Hill South Oilfield, Port au Port Peninsula,
Newfoundland. Property evaluation, prepared in accordance with National Policy 2-B for
exchange-listed companies.
Tectonics/Baker Hughes, January 2002: Prognosis and Drilling Program for Port au Port
#2 well, Garden Hill South Oilfield. Internal Report.
25
FIGURES
26
Figure 1: Regional map of inversion fairway, showing projected reservoir edge interpreted
from drilling results.
27
28
Figure 2: Structure map in depth and dolomitization edge, Garden Hill South and southern
inversion fairway.
29
30
Figure 3: Schematic profile across the Garden Hill South field, showing reservoir
geometry and well trajectories.
31
32
Figure 4: Seismic line CAH-93-5, showing erosion of top of fault block near the Round
Head Thrust. Note downcutting of platform progressively eastward approaching Round
Head Thrust.
33
34
Figure 5: Log cross-section across the platform section, PP#1-ST1 to PP#1.
Datum: sea level.
35
36
Figure 6: Cross-sectional model of karsting and dolomitization for the inversion fairway.
37
38
Figure 7: Map of the Albion-Scipio field, Michigan Basin.
39
40
Figure 8: Block diagram and cross-section through the Albion-Scipio field, showing
relationship between dolomitization, reservoir development and faulting.
41
42
Figure 9: Map and profile through Ladyfern gas field, northeastern British Columbia.
43
44
Figure 10: Schematic profile showing potential NNE along fairway, and Port au
Port #2 location relative to Port au Port #1.
45
46
Figure 11: Cross section of well location, Port au Port #2, based on top platform
structure map of Figure 2.
47
48
Plates
Plate 1: Photo of oil-stained but tight, earthy dolostone from upper porous zone at 3570
m, lower Aguathuna, PP#1-ST1. Effective porosity estimates range from 6.8% (samples)
to around 10% (logs). Grain size is 10 – 40 microns. 80 x magnification.
Plate 2: Photo of same rock but disaggregated upon immersion in cold 10% HCl bath.
Note residual well-preserved dolomite rhombs, suggesting reduction of effective porosity
and permeability by late calcite cementation.
Plate 3:
Photo of coarser, mainly hydrothermal dolomite from lower porous zone,
showing calcite content revealed by Alizarin Red staining.
Plate 4: Same rock showing disaggregation after immersion in HCl bath.
49
50
APPENDIX I: Well pressure and production history, Port au Port #1.
1
2
3
4
5
6