IN WESTERN AUSTRALIA - Department of Mines and Petroleum

will be reached in the fourth quarter of 2004. At
that time, the Buffalo Venture FPSO will be released,
the existing wellbores will be abandoned, and the
wellhead platform will be recovered and towed away
for onshore salvage.
The safety and environmental performance of the
entire Buffalo operation has been outstanding. There
were no lost time incidents or reportable
environmental incidents during the 97-day drilling
programme in 2002, some of which involved
simultaneous activities (drilling, production,
offloading and construction). The operations were a
complex sequence of activities executed under the
simultaneous operations (SIMOPS) constraints
developed specifically for Buffalo and included in
the Safety Case documentation. The Ocean Heritage
drilling rig was also new to Australia and therefore
required the development of a stand-alone Safety
Case by the drilling contractor (Diamond Offshore
Drilling, Inc.), and Bridging and SIMOPS documents,
which were developed by Nexen. The operations
also demonstrated Nexen’s commitment to protect
the environment through the successful use of drill
cuttings re-injection sub-sea, when possible, and
the use of a water based sodium silicate drilling
fluid that reduced the impact of the remaining
drilling cuttings on the sensitive Big Bank
environment.
Further to this, the Buffalo Venture FPSO achieved
four years without an LTI (Lost Time Incident) on 29
December 2003. This outstanding safety record,
which commenced at the start of production from the
field in December 1999, has continued into 2004.
Roc Oil
The Cliff Head field, discovered in 2001 by ROC,
was successfully appraised with the drilling of two
wells in January and March 2003. Cliff Head 3 was
sidetracked to core and was production tested at a
stabilised rate, constrained by surface facilities, of
477 kL (3000 bbl) of oil per day via an 11 mm
(28/64”) choke and a down hole electrical
submersible pump. The second appraisal well, Cliff
Head 4, was drilled and also cored for reservoir
information.
The EP413 JV conducted an extended production
test on Jingemia 1 (drilled in October 2002) over
the period May to August 2003, to determine the
commerciality of the oil discovery and development
strategy. During the test, rates in excess of 286
kL/d (1800 bbl/d) were recorded.
Jingemia 2 and its sidetrack Jingemia 3 were
successfully drilled in August to September 2003,
primarily to provide water injection for the field. A
second extended production test was underway on
Jingemia 1 at year-end.
Detailed engineering and design work for the Cliff
Head oil development was undertaken in 2003, and
ROC established an office in Perth to manage the
project. On 14 October 2003, the Joint Venture took
a major step towards commercial production with a
unanimous declaration of commerciality and
agreement to move forward to the Front End
Engineering and Design review stage (FEED). The
FEED contract was awarded to Worley Pty Ltd. The
decision to proceed towards FEED was based on a
proved and probable reserve estimate of 3.3 GL (21
MMbbl) of recoverable oil.
The cost of the development is yet to be
determined, but it is expected to be in the order of
$140 million, with a final decision on the investment
expected in 2004. An application for the declaration
of a location of one block was made over the Cliff
Head field on 19 December 2003.
A location of one graticular block over the Jingemia
oilfield in EP413 was gazetted in January 2003, and
in July 2003, the JV made an application for a
production licence.
Work continues on progressing the Cliff Head oilfield
towards commercial production. Subject to
satisfactory completion of FEED and receipt of
regulatory and JV approvals, it is anticipated that a
final investment decision for the project will be
made during the second quarter of 2004 and that
first oil will be produced from Cliff Head during the
second half of 2005.
Woodside Energy
Development Activities 2003
WA-271-P
Development of the Enfield oilfield has progressed
according to plan in 2003 with the project
commencing the Front End Engineering Phase in
May 2003. Contractors for the FPSO Hull, EPCm
and Turret & Mooring facilities have been awarded.
Environmental approval for the development was
given by the Commonwealth Minister for
Environment and Heritage in July. The development
is planned to come on stream in late 2006 and will
accommodate future area tie-backs such as
Laverda as ullage becomes available.
Following the disappointing appraisal result of
Laverda 2 (drilled in December 2002), Woodside
participated in the drilling of Skiddaw 1 in May
2003 in WA-255-P to appraise the northern extent
of the Laverda field. Gas and oil columns were
penetrated in Skiddaw 2 (a sidetrack to Skiddaw 1).
Feasibility studies with respect to future
development of the technically challenging Vincent
field are continuing.
WA-279-P
Development of the Blacktip gasfield progressed
into the concept selection phase in March 2003. In
June 2003, the Blacktip JV signed a Heads of
Agreement with Alcan for the supply of gas to
underpin Alcan’s planned expansion of its Gove
alumina production and bauxite mining facilities.
PWA April Edition - 2003 Review 19
First gas is currently scheduled for January 2007.
Following a further review in December, the Blacktip
development will commence Basis of Design (BOD)
studies in January 2004.
Production Activities 2003
Laminaria and Corallina
In November 1999, the Northern Endeavour FPSO
commenced production from the Laminaria and
Corallina fields in production licence AC/L5 located
in the Timor Sea.
The Laminaria and Corallina reservoirs have
performed above expectation. The onset and rate of
increase in water production and the associated
decline in productivity has been broadly in-line with
reservoir model predictions. Total produced oil to the
North end Rankin of June A platform 2003 was (image 24.13 courtesy GL. of Woodside)
Legendre
Development studies carried out in Q4, 2002
resulted in an infill drilling opportunity to develop the
poorly swept southwestern flank of the Legendre
North field. The infill well, Legendre North 4H was
drilled in April 2003 using the Ensco 56 and
commenced production on 10 June 2003.
The performance of the Ocean Legend has been
good with an annual average production rate of
4370 kL/d, with almost all gas re-injected and
minimal flaring. The maximum rate achieved during
2003 followed the drilling of Legendre North 4H and
optimisation of gas handling facilities. Cumulative
total produced oil to end 2003 was 4.429 GL.
North Rankin
The North Rankin gasfield lies 23 km northeast of
the Goodwyn field and approximately 140 km
offshore from Karratha in approximately 125 m of
water. The field was discovered in 1971 when the
NRX-01 well penetrated 565 m of gross
hydrocarbon column in Triassic, fluvio-estuarine
reservoir quality sands. The trap is structural,
comprising a large horst block complex in the main
body of the field with a zone of westerly dipping
fault blocks in the northwest part of the field.
Reservoir units gently dip northwards and sub-crop
sealing Cretaceous shales over the crest of the
field. At the northern end of the field, the top of the
North Rankin reservoir is defined by depositionally
conformable Triassic to Early Jurassic shales.
During 2003, the field produced 3.79 Gm 3 of raw
gas and 429 ML of condensate. During 2003/04,
the NRA life extension and North Rankin ‘B’ platform
will be studied to determine an optimum
development infrastructure and functionality of the
assets.
Perseus
The Perseus gasfield is located approximately 135
km northwest of Karratha in 131 m water depth.
The field lies in a graben bounded by the North
Rankin field to the east and the Goodwyn field to
the west.