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Paul
Henderson
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'Sunrise
Will Be Developed': NT Minister
Ratification
of the Timor Sea Treaty plus the extensive marketing efforts that have
been carried out should pave the way for the development of the Greater
Sunrise reservoirs, according to the Northern Territory Minister for Business,
Industry and Resource Development, Paul Henderson.
In
an exclusive interview with PESA News, the Minister said that despite
its complex geology and politics, the Greater Sunrise Field was too large
not to be developed.
"The
negotiation and completion of the Sunrise IUA (International Unitisation
Agreement) has opened the door to future development", he said.
"It
was very clear to us there are many markets that are potentially available
for a large volume of gas that could be sourced from the Timor Sea.
"It
is for these reasons that I am confident that Sunrise will be developed
in the future, however, it is difficult to predict within what time frame
at this time."
Henderson
said the securing of gas customers as a whole is of vital importance so
that the known gas reserves can be brought into the market.
"You
only have to look at the development of the North West Shelf regions in
that once a successful project is under way that in itself provides a
snowball for further exploration efforts", he said.
"We
expect the same thing to happen not only in the Greater Sunrise vicinity
but elsewhere in the Timor Sea not affected by the JPDA."
While
the controversy over Sunrise and the Timor Treaty stole much of the media
limelight over the past two years, Henderson said NT authorities are not
ignoring other key onshore and offshore petroleum assets in the region.
A
number of projects have been undertaken as part of its exploration initiative
for onshore areas, which has resulted in increased explorer interest in
the Georgina, Pedirka, Wisa and Amadeus basins.
Henderson
said while the Federal Government could do more to encourage exploration
in remotes and frontier areas such as the NT and surrounding waters, the
latest release of offshore NT acreages was "interesting" and
the amount of exploration effort will depend upon the success of the initial
development of projects such as the ConocoPhillips-led Bayu-Undan project.
Besides
Timor Sea gas fields, there are the Blacktip and Petrel/Tern fields in
the Joseph Bonarparte Basin.
The
project proponents for Blacktip (Woodside/AGIP) and Petrel/Tern (Santos)
have already began targeting big gas consumers such as the Alcan Gove
alumina refinery, McArthur River zinc deposit and the PowerWater Corporation.
Henderson
said decisions regarding the preferred gas supplier to those projects
are expected some time during this year and depend on the outcome of number
of feasibility studies that are currently under way.
"The
NT Government is an integral part of those projects and is facilitating
and been part of a number of negotiations", he said.
And
then there is the on-again, off-again multi-billion dollar PNG-to-Queensland
gas pipeline project lurking in the background as a potential strong competitor
to the Timor Sea gas fields.
While
he would prefer to see gas sourced from the Timor Sea for NT projects,
Henderson said if PNG gas is the only economically viable source for major
onshore development such as mineral processing then he would have no problem
receiving such gas.
With
three big sources of gas nearby, proximity to Asian markets and low sovereign
risk, the Government, Opposition, consultants and key industries, dubbed
'Team NT', have hit the road selling Darwin to major gas users as a potential
key location for their operations.
"It
is of course a complex issue, particularly as a number of these projects
are of considerable size and which can compete globally", he said.
"The
Chief Minister and I have been engaged in a number of discussions with
major companies and the Chief Minister has visited Pechiney and Alcan
in France and in Canada with the purpose of encouraging those companies
to locate in the NT."
In
addition to a proposal for a methanol plant to be based around the Evans
Shoal field, Henderson said there are potentially some other fields coming
on stream in the medium to long term.
"Apart
from expansions at Alcan Gove and McArthur River arising from developments
at say Petrel/Tern and Blacktip, we could see that there are opportunities
for the expansion of the Darwin LNG Plant fed by gas from any number of
sources which may include Sunrise", the Minister said.
Henderson
said the success of such projects will encourage explorers to find more
gas reserves. "I think the best example of all of this is to look
at the thirty year history of the North West Shelf and see what happened
there", he said.
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Fig.
1. Tectonic elements of the Bonaparte Basin.
Click to enlarge
Fig.
2. Stratigraphy of the Bonaparte Basin.
Click to enlarge
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Exploration
Potential Of The Timor Sea
The
Bonaparte Basin covers an area of 500,000 km2 and hosts about 250 exploration
wells, with one well per 2000 km2. It is sparsely explored by world standards
and the success rate since 1989 is 25%.
The
larger Bonaparte Basin comprises several Palaeozoic/Mesozoic rift sub-basins
of various ages and orientation, flanked to the northwest by major Triassic
platforms (Fig. 1).
The
greater basin has been affected by a complex structural history involving
two phases of Palaeozoic extension and Late Triassic compression prior
to the onset of Mesozoic extension. The tectonic elements and regional
stratigraphy of the Bonaparte Basin are shown in figures 1 and 2, respectively.
The exploration potential of the resultant sub-basins is described below.
Vulcan
Sub-basin
This complex rift basin contains 19 field discoveries and 75 exploration
wells giving a success rate of 25 %. There is a 13% success rate for fields
greater than 20 MMboe (Longley et al., 2002). This author estimates reserves
at 1.3 Tcf of gas, 31 MMbbl of condensate and 357 MMbbl of oil.
This
NE-SW trending rift basin comprises a series of horsts and graben and
associated structural terraces and is flanked to the northwest by the
Ashmore Platform (Fig.1). The major depocentres are the Swan and Paqualin
Graben which contain thick Jurassic syn-rift shale sequences, providing
excellent source rocks. These graben die out to the northeast beneath
the Neogene Cartier Trough.
In
this area salient source areas and migration pathways are decribed by
Ambrose (2003) and Kennard et al (1999). In the southern Vulcan Sub-basin
the Early-Middle Jurassic Plover Formation has sourced liquids in the
Montara, Bilyara and Maret accumulations (Edwards et al, 1996) and it
is suggested by Lisk et al (1998) that gas charge preceded oil charge
in this area.
A
local Plover source was probably complemented by charge from other Jurassic
source rocks in the Heywood Graben to the south. For instance, the Talbot
field was probably charged with oil expelled from Lower Vulcan source
rocks in this graben.
The
Swan and Paqualin Graben expelled large quantities of oil in the Tertiary
from the Jurassic Frigate Formation, probably largely coincident with
at least some charge from the underlying Plover Formation. Oil migration
along pathways of up to 60 km charged the Jabiru, Challis, Skua, Cassini
and Tenacious fields. Oil charge was prolific (over 40 live and palaeo-oil
columns are recorded) but many accumulations suffered fault breach in
the Neogene.
To
the northeast, development of the Neogene Cartier Trough resulted in the
expulsion of oil and gas from the Plover Formation. For instance the Oliver
structure retained a 200 MMbbl oil pool prior to leakage in the Neogene
(Lisk et al, 1998).The relatively large volumes of Plover derived oil
highlight the source potential of this depocentre and its margins which
have only been sparsely explored.
In
the Vulcan Sub-basin proper there is a strong chance of discovering small
to medium size fault traps (10-50 MMbbl), contingent on improved seismic
imaging of enhanced 3D seismic data sets. Several wells have addressed
hanging wall fault traps but none have tested valid closures suggesting
explorers should persevere with this play type.
Similarly,
stratigraphic plays, independent of fault seal, are attractive targets
for the more intrepid explorers; these are inherently high risk-high reward
plays but, given the prolific hydrocarbon charge in the basin, these virtually
untouched play types deserve promotion.
Northern
Bonaparte Basin
The northern Bonaparte Basin includes the numerous oil fields in the JPDA
area and the giant gas fields of Greater Sunrise and Evans Shoal to the
east. A total of 90 exploration wells has yielded 26 discoveries giving
a success rate of 29%. Longley (2002) indicates the reserves in this area
are 23.6 Tcf of gas, 612 MMbbl of condensate and 337 MMbbl of oil.
The
tectonostratigraphic evolution of this large area is described by Whittam
et al. (1996) and Shuster et al (1998). Whereas the Vulcan Sub-basin underwent
NW-SE extension during the Callovian-Oxfordian, in the JPDA area (Laminaria-Corallina,
Bayu-Undan) this phase was subordinate to later north-south extension
(Tithonian-Berriasian) which resulted in a dominant E-W structural grain.
As
in the Vulcan Sub-basin, all of the hydrocarbons are trapped at the base
of the syn-rift shales (Oxfordian-Berriasian), or at the Valanginian unconformity
in structures showing substantial uplift. Source rocks extend from the
Permian and the pre-rift Plover sequence, through the syn-rift Callovian
to Berriasian sequences, to the post-rift Echuca Shoals Formation.
The
JPDA area has undergone moderately intensive exploration but significant
potential remains in the vicinity of the Malita Graben and Sahul Platform
for wet gas and subordinate oil. Condensates from the Greater Sunrise
field have been sourced from the Plover Formation (Longley et al, 2002)
and the field was filled to spill at 10ma or less.
The
Plover source rock is in the gas /liquids window over a wide area of the
Sahul Platform and there is good potential for further wet gas discoveries.
In the Malita Graben the Plover source is today overmature but has sourced
dry gas in the Evans Shoal field.
However,
drilling away from the fields is sparse and the Malita Graben sequence
has not been fully penetrated. Hence the axial development of the key
source rock, the Oxfordian Shales, remains speculative but it is noteworthy
that Woodside Petroleum interpret a thick section of Oxfordian sediments
in the axis of this trough (Longley et al. 2002). This signifies that
once exploration resumes in this largely gas prone province there is a
likelihood of significant oil/wet gas pools being discovered.
Petrel
Sub-basin and Bonaparte Inboard Shelf
This summary is largely based on Longley et al (2002). The Petrel Sub-basin
is also described by Colwell and Kennard (1996), McConachie et al. (1996)
and Edwards et al. (1996). This area contains 18 field discoveries from
67 exploration wells yielding a success rate of 27%. The sub-basin is
estimated to contain 3.9 Tcf of gas, 7 MMbbl of condensate and 19 MMbbl
of oil.
The
gas fields in the area include older discoveries such as Petrel and Tern
which complement more recent discoveries at Rubicon and Blacktip. The
structures are faulted, sometimes salt cored , antilcines or tilted fault
block traps at regional base Triassic seal level.
They
contain dry gas within Permian sandstones, and Permian fluvio-deltaic
shales are believed to be the source. In the south, the Turtle and Barnett
oil discoveries occur in Carboniferous sandstones believed to have been
sourced from intraformational marine shales. Exploration is ongoing in
this area as potential gas marketing opportunities begin to open up in
the Northern Territory and oil exploration continues in the southernmost
areas.
Northern
Browse Basin
This portion of the Browse basin contains five discoveries from 15 exploration
wells yielding a success rate of 33%. Reserve numbers are not available
for the four most recent gas discoveries, ie Crux, Argus, Kalyptea and
Keeling.
The
transition between the northern Browse Basin and the Vulcan Sub-basin
is marked by a major NW trending Proterozoic fracture system (O'Brien
et al , 1999) which marks the updip termination of three important, south
plunging graben.
These
are the Woodbine, Kimberley and Heywood Graben which have generated oil
and gas from multiple stratigraphic horizons ranging from the Triassic
through to the Cretaceous Echuca Shoals Formation. This is evidenced in
the Crux discovery from GOI studies. Triassic reservoir quality is exceptionally
good, possibly a result of hydrocarbon charge restricting diagenesis.
In the northern Browse Basin Jurassic source rocks have sourced both oil
(Talbot oil field and a palaeo-oil column in Keeling 1) and gas (Keeling,
Crux and Argus).The remaining potential for wet gas is high while evidence
for Triassic and Oxfordian oil prone source rocks facilitating multiple
oil charges is compelling, but structures drilled to date have been flushed
by gas.
Exploration
Potential Summary
The exploration history of the Timor Sea area demonstrates that it contains
all the prerequisites for additional hydrocarbon discoveries with key
reservoir, source rock, trapping and maturity trends overlapping over
a wide area.
Areas
highlighted for future exploration are 1)The southern Vulcan Sub-basin
and northern Browse transition zone for Frigate/ Plover sourced oil in
fault dependent traps up to 50 MMbbl in size, plus wet gas potential.
2) The Cartier Trough for Plover sourced oil and gas 3) The Montara Terrace
for Frigate/Plover sourced stratigraphic plays associated with the Montara
Formation 4) Platform areas adjacent to Greater Sunrise for Plover sourced
wet gas 4) Structural terraces bounding the Malita Graben for gas, and
displaced, Oxfordian sourced oil.
New
play types are one key to future discoveries and hanging wall fault traps
and Kimmeridgian/Tithonian stratigraphic plays along the faulted margins
of the Londonderry high are examples.
There
are numerous other exploration opportunities in this vast and geologically
diverse area. Exciting gas marketing opportunities are arising in the
Northern Territory and the pending construction of the Bayu-Undan LNG
plant and pipeline facilities will have important implications for exploration
in the region.
References
AMBROSE, G.J., 2003, Jurassic sedimentation in the Bonaparte
Basin: New models for reservoir-source rock development, hydrocarbon charge
and entrapment. Symposium, Eds Baillie, P. and Elliis, G. Timor Sea Petroleum
Geoscience, Bonaparte Basin and Surrounds. In press.
COLWELL, J.B. AND KENNARD, J.M., 1996. Petrel Sub-basin study 1995-1996.
Summary Report, Australian Geological Survey Organisation Record, 1996/40,
122 p.
EDWARDS, D.S. AND SUMMONS, R.E., 1996. Petrel sub-basin study 1995-1996.
Organic geochemistry of oils and source rocks. Australian Geological Survey
Organisation, Record 1996/42, 77 p.
KENNARD, J.M., DEIGHTON I., EDWARDS, D.S., COLWELL, J.B., O'BRIEN G.W.
AND BOREHAM, C.J., 1999. Thermal history modelling and transient heat
pulses: new insights into hydrocarbon expulsion and 'hot flushes' in the
Vulcan Sub-basin, Timor Sea. APPEA Journal 39, pp 177 - 207.
LISK, M., BRINCAT, M.P., EADINGTON, P.J. AND O'BRIEN, G.W. 1998. Hydrocarbon
charge in the Vulcan Sub-Basin: Purcell, P.G. and R.R.. The sedimentary
basins of Western Australia 2. Proceedings of PESA Symposium, Perth, WA,
pp 287-305.
LONGLEY, I.M., BUSSENSCHUETT, C., CLYDSDALE, L., CUBITT, C.J.,DAVIS, R.C.,
JOHNSON, N.M., MARSHALL, A.P., MURRAY A.P., SOMERVILLE, R., SPRY, T.B.
AND THOMPSON, N.B. 2002. The North West Shelf of Australia - a Woodside
perspective. In: Keep, M. and Moss, S.J. The Sedimentary Basins of Western
Australia 3. Proceedings of PESA Symposium. Perth, W.A., pp 27-28.
Mc CONACHIE, B.A., BRADSHAW, M.T. AND BRADSHAW,J., 1996. Petroleum systems
of the Petrel Sub-basin - an integrated approach to basin analysis and
identification of hydrocarbon exploration opportunities. APPEA Journal,
36(1),248-268.
O'BRIEN, G.W., MORSE, M., WILSON,D., QUAIFE P., COLWELL,J., HIGGINS, R.,
FOSTER, C.B. 1999. Margin scale basement involved compartmentalisation
of Australia's northwest shelf. A primary control on basin scale rift,
depositional and reactivation histories. APPEA Journal 39, pp 40-61.
SHUSTER, M. W., EATON, S., WAKEFIELD L.L. AND KLOOSTERMAN, H.J., 1998.
Neogene tectonics, Greater Timor Sea, offshore Australia: implications
for trap risk. APPEA Journal 38(1) pp 351-379.
WHITTAM, D.B., NORVICK, M.S. AND McINTYRE C.L., 1996. Mesozoic and Cainozoic
tectonostratigraphy of western ZOCA and adjacent areas. APPEA Journal
36 (1), pp 209-232.
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Exploration
History Of The Timor Sea Area, Bonaparte Basin And Surrounds
Onshore
Exploration
Exploration in the onshore Bonaparte Basin was initiated in 1839 when
the crew of the HMS Beagle found bitumen in a well dug for water at Holdfast
Reach in the Victoria River estuary.
By
the turn of the 20th Century several coal bores, less than 304.8 m (1000
ft) deep, had been drilled around Port Keats on the coast of the Joseph
Bonaparte Gulf. There was little further exploration until the early 1960s
when Spirit Hill-1 and Bonaparte -1 were drilled onshore, the latter drilled
by Alliance Oil Development to a depth of 3210 m.
Field
mapping in the onshore Bonaparte Basin was initiated by the BMR and CSIRO,
later in conjunction with Australian Aquitaine Petroleum. This resulted
in publication in a series of 1:250,000 geological map sheets covering
the onshore Bonaparte Basin. More recently, Laws and Brown (1976) and
Laws (1981), published summaries of the onshore geology and drilling results.
Experimental
seismic surveys were conducted by the BMR in 1956, but the first use of
the seismic method in the Bonaparte Basin for petroleum exploration began
in 1960 with a 100 km length reflection survey conducted near Spirit Hill.
Further seismic was acquired through to the early seventies, the most
significant drilling results being a gas flow from Bonaparte -2 and oil
shows in Kulshill-1.
Seismic
acquisition recommenced in 1980 to 1984 and the gas discovery, Weaber-1
was drilled in 1982. Additional small discoveries occurred through the
1980s (eg Waggon Creek) but none has been commercialised.
Offshore
Exploration
In the offshore, early work focussed on the Browse and Bonaparte basins
and the initial wells were drilled by BOCAL/Woodside in 1967-1969 in the
west of the basin (Ashmore Reef-1 and Sahul Shoals-1). The Mesozoic was
the main target of this exploration. ARCO and Aquitaine targetted the
Palaeozoic as they explored the southeast of the basin (Lacrosse-1 and
Petrel-1).
These
exploration groups dominated exploration in the basin until the 1980s
when BHP, Western Mining Corporation and Bond Corporation led new joint
ventures into relinquished areas. Oil discoveries at Skua, Jabiru and
Challis triggered an extended period of oil exploration in the Vulcan
Sub-basin which has continued through to the present day.
Exploration
drilling in the northern Bonaparte Basin began in 1971 with the drilling
of Flamingo-1 but exploration was frozen in 1976 due to a seabed boundary
dispute between Australia and East Timor.
The
period leading up to the gazettals by the Australia-Indonesia Joint Authority
for the Timor Gap Zone of Cooperation (ZOCA) saw only minor exploration
in surrounding platform areas. Once exploration got underway in ZOCA a
number of oil and gas discoveries followed, the largest being the Bayu-Undan
gas-condensate discovery.
In
1994 the Laminaria/Corallina oil discoveries sparked renewed exploration
in the northern Bonaparte Basin which continued through the turn of the
century, resulting in several small oil discoveries.
During
the past five years, 55 exploration wells in the Timor Sea have yielded
15 technical discoveries with a discovery rate of 27%, very close to the
Timor Sea average success rate of 25%.
However,
these were mainly gas/ gas liquids and small oil discoveries, which could
not be commercialised. Significant discoveries during this period included
extensions to the Greater Sunrise field (gas-condensate, Sunset West -1,
Bard -1), Chuditch-1 (gas-condensate) , Crux-1 (gas-condensate), Argus-1
(gas), Audacious-1 (oil), Blacktip-1 (gas), Abadi-1(gas-condensate) and
Cash-1(gas).
The
Timor Sea petroleum geoscience symposium will address technical issues
crucial to improving not only the discovery rate but also the rate of
commercialisation. The main goals are to establish the technical criteria
to facilitate:
1) Discovery of remaining oil reserves.
2) Discovery of new liquids rich gas deposits viewed to have commercial
potential in the short term as pipeline and LNG
facilities become available and markets are established.
3) Discovery of gas deposits in the Petrel Sub-basin and elsewhere to
lend critical mass to future gas projects in the Timor Sea which have
a short to medium term chance of commercialisation.
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