Production and Development - Column, Forecasts and Descriptions

2005 Production and development - statistics, forecasts and descriptions

Crude Oil and condensate forecasts

Petroleum offshore production developments, 2005

2005 Production and development - statistics, forecasts and descriptions

Table 1 - Daily petroleum production rates, 2005 [PDF 39KB]

Table 2 - Crude oil and gas production by basin, pre-1996 and 1996-2005 [PDF 64KB]

Table 3 - Forecast of crude oil and condensate production from Australia's identified accumulations and crude oil production from undiscovered accumulations- 2005 [PDF 37KB]

Table 4 - Forecast of crude oil production from Australia's identified accumulations and from undiscovered accumulations- 2005 [PDF 37KB]

Table 5 - Forecast of condensate production from Australia's identified accumulations- 2005 [PDF 34KB]

Table 6 - Australia's production and demand for crude oil and condensate (thousands of barrels per day) [PDF 35KB]

Crude Oil and condensate forecasts

Figure 1 - Australia's annual production of crude oil and condensate 1975-2005 and forecast annual production 2006-2025 [PDF 11KB]

Figure 2 - Australia's annual production of crude oil 1975-2005 and forecast annual production 2006-2025 [PDF 10KB]

Figure 3 - Australia's annual production of condensate 1975-2005 and forecast annual production 2006-2025 [PDF 10KB]

Crude oil and condensate forecast for 2006-2027

The forecast of production given in this section is based on current estimates of production from identified and undiscovered resources. Geoscience Australia estimates are provided at various probability levels to reflect the uncertainty surrounding the development of discovered accumulations (e.g. a production estimate at the 90% probability level means that there is a 90% chance of production being at least as high as the figure shown).

The figures for production from identified resources incorporate estimates of production from individual developed fields as well as estimates of reserves and timing of development of identified but undeveloped fields. The major factors affecting the accuracy of oil production estimates for identified fields are reserves growth in offshore fields and delays in the startup and interruptions to production from offshore fields. As a result the lower probability levels reflect the scope for increases in the reserves estimates on which the forecasts are based.

The accuracy of the production estimates is also dependent on the timing of future gas developments with their associated condensate production. In some cases, the cycling of dry gas allows accelerated production of condensate.

Figure 1 [PDF 11KB] shows the production of crude oil and condensate from 1975 to 2005 and Figure 1 [PDF 11KB] and Table 3 [PDF 37KB] show forecast production from 2006 to 2027. The forecast includes production of crude oil and condensate from accumulations that had been discovered by the end of June 2005, plus production of crude oil and condensate from undiscovered accumulations. The 2006 forecast includes 10% of production from the Joint Petroleum Development Area (JPDA).

Crude oil forecast for 2006-2027

Figure 2 [10KB PDF] shows crude oil production from 1975 to 2005 and Figure 2 [PDF 10KB] and Table 4 [PDF 37KB] show a forecast of crude oil production from 2006 to 2027. The forecast is based partly on Geoscience Australia and company estimates of crude oil production from accumulations that had been discovered by end of June 2005 (identified accumulations), and partly on estimates of crude oil production from undiscovered accumulations. The forecast includes 10% of production from the JPDA.

Condensate forecast for 2006-2027

Figure 3 [10KB PDF] shows production of condensate from 1975 to 2005 and Figure 3 [PDF 10KB] and Table 5 [PDF 34KB] show a forecast of condensate production from 2006 to 2027. The forecast is based on company and Geoscience Australia estimates of production from accumulations that had been discovered by June 2005 and for which some production planning has been carried out. The forecast includes 10% of production from the JPDA.

Petroleum offshore production developments, 2005

Table 7 - Australia's offshore production facilities [PDF 79KB]

Gippsland Basin

Otway Basin

Bass Basin

Bonaparte Basin

Browse Basin

Carnarvon Basin

Perth Basin

Gippsland Basin


Development of the Basker-Manta-Gummy project commenced in February 2005 when Anzon Australia Limited submitted to the Government the preliminary field development plan as a precursor to an application for a Production Licence. Work on the Basker-Manta-Gummy project in 2005 consisted of engineering design, procurement and construction aspects of the project, and culminated with the commencement of the Extended Production Test in November 2005.

The Basker, Manta and Gummy fields are located in the Offshore Gippsland Basin in Retention Leases VIC/RL6, VIC/RL9 and VIC/RL10. The Basker Field was discovered by the Basker-1 well in 1983 and the Manta Field was discovered by the Manta-1 well in 1984. The Basker-1 well discovered twelve thin oil and gas reservoirs in the lowermost part of the Latrobe Group. Follow-up wells in the adjacent Manta and Gummy structures (1984 and 1990) discovered further oil and gas reservoirs.


In June 2005, Esso submitted to the Government an application for a Production Licence for the Kipper gas and oil field.The production from the field is expected to commence in 2009.

The field is located approximately 42 km offshore from the Gippsland coastline, about 60 km east of Lakes Entrance, in water depth of approximately 100 m. One part of the field is under Retention Lease VIC/RL2 granted to Esso (operator, 25%), BHP Billiton (25%), Woodside (30%) and Santos (20%), while another part is in Production Licence VIC/L9 granted to Esso (operator, 50%) and BHP Billiton (50%). As part of the Memorandum of Understanding between the partners of the Retention Lease VIC/RL2 and Production Licence VIC/L9, the Kipper field will be developed via unitisation.

The joint venture partners propose to develop the Kipper field by installation of a number of subsea wells and associated subsea pipeline infrastructure. The recovered gas would then be piped through existing Esso and BHP Billiton infrastructure and processing facilities. Development of the field is estimated to cost between A$250 million and A$300 million.

Otway Basin


A production licence (VIC/L24) for Casino development was granted to Santos in April 2005. Casino-4 and Casino-5 wells were drilled and completed for production. New 35 km offshore and 12 km onshore pipelines were constructed. The onshore and offshore sections were linked using a horizontally directionally drilled shore crossing at Two Mile Bay. The production started on 1 January 2006.

The Casino development includes the drilling of subsea completed development wells and the installation of a pipeline from the field to beneath the coastline near Port Campbell, continuing to the existing Iona gas plant and underground storage site. Gas will be processed in the plant prior to its distribution to Victorian and interstate customers through the existing pipeline network. Small quantities of water and condensate will be removed at the Iona plant facility. The water will be disposed through the plant's existing water treatment facility and the condensate will be stored for transport to the Geelong refinery by road tankers.

The Casino gas field was discovered in September 2002 by the Casino-1 well which encountered a 47-metre gas column in the Waarre formation. The field is located offshore 29 km southwest of Port Campbell in 70 m of water.

Geographe and Thylacine

Government approval for the development of the Thylacine and Geographe gas condensate fields was granted to Woodside in April 2004. In May 2004 the Joint Venture Partners approved development of both fields and construction work started in early 2005 and production from the Thylacine field started in 2007.

The fields are located in the offshore Otway Basin, 55 - 70 km south of Port Campbell in Victoria. The fields lie in exploration permits, VIC/P43 and T/30P respectively. The Thylacine and Geographe fields were discovered in 2001 by the drilling of the Thylacine-1 and Geographe-1 exploration wells following the 1999 Investigator 3D seismic programme. The Thylacine-1 exploration well was drilled in May 2001 and discovered a 281 m gross gas column. The Thylacine-2 appraisal well was drilled in August 2001 and discovered a 230 m gross gas column. The Geographe-1 exploration well was drilled in June 2001 approximately 15 km north of the Thylacine discovery and recovered gas by wireline formation sampler at three levels; 1831.7mRT, 1896.4mRT, and 2015.8mRT.

Thylacine and Geographe fields will be developed in stages. The first stage of the project involves the initial expenditure of A$810 million for the development of the Thylacine gas field in the offshore Tasmania permit T/30P, about 70km south of Port Campbell in a water depth of 100 m. The Geographe gas field, 55km south of Port Campbell in the offshore Victoria permit VIC/P43, will be connected to the main offshore pipeline about 2-3 years after Thylacine comes into production. The total project cost is estimated to be A$1.1 billion.

The first stage of the project includes:

Construction of the onshore gas processing plant north of Port Campbell near the existing Iona facility.

Construction of the 11.5 km onshore pipeline from the shore crossing to the gas plant.

Shore crossing at Port Campbell.

70 km of offshore pipeline tied-in to the Thylacine offshore platform.

Construction and installation of the offshore platform over the Thylacine gas field and drilling of the four Thylacine production wells.

Initially the Otway Gas Project will produce about 1.557 BCM (55 BCF) of sales gas a year.


In January 2005 first gas production was achieved from the Minerva gas field operated by BHP Billiton. The field is located in the Otway Basin, in production licence VIC/L22 , approximately 10 km from Port Campbell in 60 m of water. It was discovered in 1993 by the Minerva-1 exploration well. The field plateau production rate is 3.82 million m3/d (135 Mscf/d) of sales gas, and up to 79.5 kL/d (500 bbl/d) of stabilised condensate. The development consists of two subsea wells producing through a 10' diameter, 10km long pipeline to shore. The pipeline crosses the shore via a directionally-drilled crossing under the beach and then moves to a gas processing plant a further 4.5 km inland. The field has an expected life of 10 years.

Bass Basin


The Yolla development has suffered from some delays due to the identification of a number of defects in the key systems of the project. Defect rectification works on the project and commissioning of the onshore plant was done in 2005. The production from the Yolla field started in 2006.

The Yolla gas and oil field is located in the production licence T/RL1 in the Bass Basin, 120 km offshore from Tasmania and 220 km southeast of Melbourne in a water depth of 80 m. The field was discovered in 1985 by Amoco's well Yolla-1 which intersected gas in the Intra-Eastern View Coal Measures (EVCM) between 2718 and 3000 m. Yolla 1 also tested oil and gas from the Top EVCM reservoir unit at around 1800 m. Yolla 2 was drilled in 1998 as a downdip appraisal of the gas column intersected in Yolla 1 and tested gas in the Intra-EVCM reservoir. The reserves are publicly estimated at 6.51 BCM (230 BCF) of sales gas, 1 million tonnes of Liquid Petroleum Gas and 2.23 GL (14 million bbl) of condensate. The Yolla field development consists of:

Conventional steel platform.

Two deviated development wells.

350 mm diameter 147 km long plain carbon steel subsea pipeline for the export of raw gas and condensate to an onshore treatment plant near Lang Lang in Victoria.

Subterranean shore crossing near Kilcunda in Victoria.

Water handling facilities in excess of 95.3 kL/d (600 bbl/d), gas dehydration and compression facilities.

Provision for the tie-in of additional Yolla gas reserves and future discoveries and provisions for wellhead compression facilities.

A further two wells are planned to maintain deliverability. The offshore platform will not normally be staffed. The platform supports the wellheads and the gas processing facilities used to treat the gas extracted from the reservoir to the quality where it can be piped to shore. The water extracted with the gas-stream is separated, treated on the platform and then discharged overboard.

Bonaparte Basin


On 23 September 2005 AED Oil Ltd submitted a Preliminary Field Development Plan (PFDP) for the Puffin oil field. The field is located in the Ashmore Cartier Exploration Permit AC/P22 in the Vulcan Sub-Basin. The Permit is located approximately 80 km south west of the Jabiru and Challis oil fields and approximately 25 km from the Skua oilfield. The Company acquired its interest from Century and its nominee Attune on 31 January 2005.

Development of the field was proposed using the conventional Floating Production Storage and Offloading vessel (FPSO) and subsea wells connected to the FPSO by flexible flowlines and umbilicals. Storage capacity in the FPSO will allow the transfer of stabilized crude oil to shuttle tankers for transport to market. The Puffin Production Licence AC/L6 was granted 12 April 2006.

Browse Basin


In 2005 INPEX Browse Ltd was evaluating various developmental scenarios, including such possibilities as LNG and GTL supply, as well as the pipeline supply of raw gas to Australia, targeting the initiation of commercial production after 2010.
The Ichthys field was first indicated by the Brewster-1A exploration well drilled by Woodside in 1980 in exploration permit WA-35-P. Inpex acquired a 100% interest in WA-285-P in August 1998 and conducted a 2D seismic survey in the same year. In 2000 and early 2001, INPEX drilled three exploration wells and tested gas and condensate from the three wells. WesternGeco acquired 3D seismic data as a Multiclient survey in this region in 2001 and Inpex purchased and reprocessed a part of this data for evaluation. In 2003 and early 2004, Inpex drilled three exploration and appraisal wells and confirmed gas and condensate in all three wells.

Carnarvon Basin


In May 2005, Woodside submitted the final field development plan for the Angel gas field to the Government. The development drilling was planned to begin 2007, with the platform due to be fully operational by the end of 2008.
The Angel gas-condensate field is located approximately 53 km east-northeast of North Rankin A and some 123 km north-west of the onshore gas plant at Dampier in 80 m of water. The field lies almost entirely within the Angel Primary Production Licence WA-3-L.

The Angel field was initially delineated by 2D seismic in the late 1960s to early 1970s and discovered in 1971 by the Angel-1 well. The Angel discovery was subsequently appraised by two wells, Angel-2 and Angel 3, drilled during the early 1970s. The Angel-4 appraisal well was drilled during 1990 in the north-west area of the Angel field, intersecting a gross gas column of some 67 m. In December 1977 Woodside made applications for primary and secondary production licences over the Angel field which were awarded to the North West Shelf Venture on September 30 1980.

The Angel field development consists of a jacket type platform capable of processing 22.65 million m3/d (800 million scf/d) and 949 kL/d (50 kbbl/d) of condensate via 3 individually tied back subsea wells. The processed gas will be exported via a 49 km, 30' diameter carbon steel pipeline tied into the NWS first trunkline and commingled with the production from the North Rankin A facilities. The Angel gas field has an expected field life of approximately eight years. The 7500 tonne Angel jacket substructure and 7000 tonne topside are expected to be fully operational by fourth quarter 2008.


Enfield oil project was more than 60% complete. The facility was built at Samsung Heavy Industries' shipyard in South Korea. In April 2005 the FPSO Nganhurra was launched from its floating dry dock. Topsides facilities were installed and integrated with the hull during the remainder of 2005. In March 2005 the Transocean operated semi submersible drilling rig Jack Bates started work on the drilling of 13 wells development wells.

The Enfield oil field is located approximately 16 km north of the Ningaloo Reef in exploration permit WA-271-P in offshore Carnarvon Basin. Five wells have appraised the Enfield accumulation. All except Enfield-2 tested heavily biodegraded oil with an API of 22º, while a gas cap was encountered in the Enfield 5 well.

The Enfield development comprises subsea wells tied back with flowlines to the FPSO Nganhurra. The FPSO Nganhurra is of double hulled construction, with disconnectable mooring, its own propulsion system to allow for evasion of tropical cyclones and a storage capacity of approximately 143,000m3 (900 kbbl). In normal operations an offshore crew of around 34 personnel are on board the vessel. After stabilisation on the FPSO, export crude oil is stored in the FPSO's tanks and periodically exported through an offloading hose to tandem moored offtake tankers. Typical export cargoes are approximately 87,443 m3 (550 kbbl). Facilities were designed for 20 years operation. The FPSO is intended to remain on station for the entire design life without recourse to dry docking for maintenance or survey. The produced water and surplus gas are reinjected back into the reservoir unit.

Production started in July 2006. The FPSO was positioned in a water depth of 550 m.

Exeter and Mutineer

The Exeter and Mutineer fields commenced production on 29 March 2005. Production rates during 2nd quarter 2005 averaged 11447 kL/d (72 kbbl/d). The fields are located in the northern part of the Dampier Sub-basin of the Carnarvon Basin in Western Australia in water depths ranging from 140 to 160 m. The fields are approximately 150 km north of Dampier and 40 km north of the Cossack Pioneer FPSO.

The fields are developed via the FPSO vessel MODEC Venture II moored between the two fields, horizontal production wells equipped with down-hole electrical pumps to provide artificial lift and seabed multi-phase pumps at production and pumping manifolds. One production and pumping manifold is positioned at each field. Provision is also included for water injection if necessary. Subsea flowlines connect each of the Mutineer and Exeter production manifolds to the FPSO. The FPSO is a disconnectable, turret moored unit with product offloading to trading tankers via a floating hose and provision for processed crude oil storage. All process separation and treatment of the Mutineer and Exeter fluids occur onboard the FPSO. The production capacity for the FPSO is 22 ML/d (140 kbbl/d), with a design oil throughput of 15.9 ML/d (100 kbbl/d). In 2005 production rates were on average between 11.1 and 12.7 ML/d (70 and 80 kbbl/d). The field life is estimated at 7 to 12 years.


In July 2005 ChevronTexaco Australia Pty Ltd announced its decision to move the Greater Gorgon development into the Front End Engineering and Design (FEED) phase. The FEED scope includes the establishment of a two train (10 mtpa) LNG facility and domestic gas plant on Barrow Island, which lies directly between the Greater Gorgon gas fields and the Western Australian mainland.

The Gorgon gas project involves the establishment of a liquefied natural gas facility on Barrow Island. The Greater Gorgon area is situated approximately 130 km off the north-west coast of Western Australia and includes Gorgon, West Tryal Rocks, Spar, Chrysaor, Dionysus, Io/Jansz, Orthrus, Geryon and Urania fields. The Greater Gorgon area fields contain publicly reported gas reserves in excess of 1100 BCM (40 Tcf).

The Gorgon development consist of subsea development wells, subsea gathering system, a 70 km subsea pipeline to Barrow Island and a gas processing facility located on Barrow Island. The base case for the initial development of Gorgon and Jansz-Io fields (see below) is a two-train Liquefied Natural Gas (LNG) processing facility producing approximately 10 million tonnes of LNG per annum, as well as delivering 9.76 million m3/d (300 million scf/d) of natural gas to existing mainland domestic gas infrastructure. Carbon dioxide will be removed and re-injected into deep saline water reservoirs.


In June 2005, Mobil Exploration and Producing Australia Pty Ltd submitted to the Government the preliminary field development plan for the Jansz-Io gas field, as a precursor to an application for a Production Licence.

The Jansz-Io gas field is located in the Carnarvon Basin approximately 200 km off the coast of Western Australia in 1325 m water depth. The field was discovered in April 2000 by the Jansz-1 well in permit area WA-18-R. This was followed by Io-1 in January of 2001 in the adjacent permit area WA-25-R. Appraisal wells Jansz-2 and Jansz-3 were drilled in 2002 and 2003 respectively. The Jansz-3 well was production tested and confirmed the high reservoir quality and deliverability of the Jansz-Io gas field.

It is proposed to develop the Jansz-Io field in conjunction with the Gorgon field. Each field will supply gas to a new build LNG plant located on Barrow Island. Initial development of Jansz-Io will be completely subsea with full wellstream production delivered to the onshore LNG plant via a single 30 'carbon steel flowline.

It is proposed to develop the field in stages. The initial development includes a single 6-slot manifold and five large bore development wells with a 30 ' carbon steel flowline, an 8 ' Mono Ethylene Glycol line and an 8 ' utility line back to Barrow Island. Stage 2 developments will add a second 6-slot manifold and 5 additional development wells, approximately 12 years after start-up. Finally, approximately 20 years after start-up, an offshore compression facility will be installed along with the associated risers, flowlines and infrastructure.

John Brookes

Production from the John Brookes gas field commenced in September 2005, producing at an initial flow rate of approximately 1.7-2.3 million m3/d (60-80 million scf/d). John Brookes is located 60 km northwest of Varanus Island.

John Brookes was discovered in November 1998 by the John Brookes 1 exploration well. John Brookes-1 well was drilled to a total depth of 3741 m and intersected an 80 m gross hydrocarbon column. The well was tested over two separate zones and achieved a combined flow rate of 1.51 million m3/d (53.4 million scf/d) of gas and 11.13 kL/d (460 bbl/d) of 46o API condensate. The appraisal wells, Thomas Bright-1 (drilled in 2003) and Thomas Bright-2 (drilled in 2004) confirmed economic viability of the field.

The field development consists of an unmanned, 6 slot wellhead platform, 3 production wells, and a single three-phase 18 ' diameter 55 km long pipeline linking the wellhead platform to the Varanus Island gas treatment facilities. In the Varanus Island facilities condensate is removed from the gas and stored and the raw gas is processed into sales quality gas and sent to mainland Western Australia via two 100 km long sales gas pipelines which connect into the Dampier-Bunbury and Goldfields Gas Transmission trunklines. The existing Varanus Island facilities were upgraded by the end of 2005 increasing the gas processing capacity to approximately 6.79 million m3/d (240 million scf/d).


In December 2004 Woodside's 'Perseus over Goodwyn' project (PoG) received final investment approval. The field lies within the graben between the Goodwyn and North Rankin horsts. The project first phase comprises three subsea wells tied back to the Goodwyn-A platform via a 16 'diameter pipeline. The wells were planned in the southern and western parts of the Perseus field to drain reservoirs not directly drained by the Perseus wells drilled from the North Rankin A platform. Current plans also incorporate development of the liquids-rich Searipple reservoir by one Searipple subsea well tied back to Goodwyn-A platform via the Perseus subsea pipeline. The PoG development drilling started in the first quarter of 2007. The Perseus field has an expected remaining life in excess of 30 years, based on current production forecasts and field expectation volumes.


In December 2005 Woodside Energy Limited announced that it had signed a Heads of agreement with Tokyo Gas for the supply of between 1.5 and 1.75 million tonnes of LNG per year, for 15 years, on an ex-ship basis from Woodside's 100% owned Pluto gas field in Western Australia. The agreement allows for an option to extend for a further 5 years, with deliveries starting from the end of 2010. The final sales and purchase agreement is expected to be negotiated by the end of 2006 and would be conditional on a final investment decision by mid-2007. The Heads of Agreement also provides for Tokyo Gas to purchase a 5% equity interest in the Pluto project. Pluto project was referred for state and federal government environmental review and an application for major project facilitation was also lodged with the Australian Government.

The Pluto gas field is located some 190km north-west of Karratha in permit WA-350-P and was discovered in April 2005 by the Pluto- exploration well. The current development options for the Pluto LNG Project include an offshore production platform, 200 km long subsea pipeline to an onshore gas treatment plant, up to two LNG processing trains with an estimated capacity of between five and seven million tonnes per annum, LPG and condensate storage tanks, loading jetty and associated infrastructure. The field would be developed by at least six sub sea wells which would be tied back to the offshore facility. Concept selection and refinement of development options will be done concurrently with field appraisal work. Woodside have assessed several plant sites and the preferred onshore processing site is the Burrup Industrial Estate on the Burrup Peninsula, with processing facilities located near Hearson Cove and storage and loading facilities located at nearby Holden Point. Alternative sites at Onslow, West Intercourse Island and Cape Preston were also assessed. The Western Australian Department of Industry and Resources has reserved land for the Pluto development within the Burrup Industrial Estate near Karratha.


In November 2005 BHP Billiton and Woodside Energy approved the A$814 million development of Stybarrow oil field. The Stybarrow oil field is located 56 km northwest of Exmouth offshore Western Australia with the Eskdale oil and gas field another 12 km further northwest in the Exmouth Sub-basin of the Southern Carnarvon Basin. The field is in exploration permit WA-255-P (2) in 825 m of water. Stybarrow will be Australia's deepest water oil development. The field was discovered in February 2003. The development proposal consists of the following components:

Seven subsea wells (4 horizontal producers, 3 deviated water injectors) for the production of hydrocarbons from the Stybarrow field, one horizontal subsea well for the production of hydrocarbons from the Eskdale field and one deviated subsea well for the injection of excess gas into the crest of the Eskdale field.

Flowlines from the subsea wells to a Floating Production Storage and Offloading facility (FPSO).

Control umbilicals from the FPSO to a subsea distribution unit and from the distribution unit to the wells.

The FPSO will be anchored at the field by a disconnectable mooring system.

The FPSO will be a double-hull vessel with a topsides plant capable of processing 12719 kL/d (80 kbbl/d) of oil.

Produced water will be re-injected into the Stybarrow field.

The first oil is expected in early 2008 and the field life is estimated at 20 years. The plateau production rate is forecasted at 12719 kL/d (80,000 bbl/d).


In December 2005 Woodside provided advance notice to the Government of the WA-28-L Joint Venture's plan for submission of the preliminary Vincent Field Development Plan. Vincent is covered by the Enfield Production Licence (WA-28-L). Several development options are being assessed, with environmental approvals processes for Vincent triggered in May 2005. The Joint Venture final investment decision is expected in March 2006. The current plan for first oil production from the Vincent accumulation is in 2008.

The Vincent oil field is located approximately 5 km north-east of the Enfield field in offshore Carnarvon Basin in 370 m water depth. The field was discovered in December 1998. The discovery well penetrated a 12 to 19 m thick oil rim in the Lower Barrow Group. The oil is heavily biodegraded and oil with an API of 17º.

Perth Basin

Cliff Head

The Cliff Head oil field development progressed in 2005 as planned and production started in May 2006.

In October 2005 the Ensco 67 jackup rig arrived on location and started Cliff Head drilling and completion program of 6 production wells and 2 water injection wells.

The drilling program was completed in December 2005.

The Cliff Head pipelines, power cable and umbilical were successfully completed on 15 November 2005.

Construction and pre-commissioning of the topsides for the Cliff Head 'A' platform was completed in Malaysia and arrived at the Cliff Head site in late January 2006.

In December 2005 the construction of the onshore production facilities was 80% completed.

The Cliff Head development includes an unmanned offshore production platform tied back to an onshore processing facility, where power generation, processing, storage and water injection facilities will be located. Export will be via truck to the BP Kwinana refinery or by truck to Geraldton for shipping.

The Cliff Head oil field was discovered at the end of 2001 in the offshore Perth Basin permit WA-286-P. The field is situated approximately 11 km off the Western Australian coastline in 16 m of water. The Cliff Head-1 well commenced drilling on 25 December 2001 and discovered a 5 m oil column in the primary Permian reservoir objective. The field was successfully appraised by three wells. On two appraisal wells the reservoir was cored and on one well a production test was conducted that flowed at stabilised rates up to 477 kL/d (3 kbbl/d) using electrical submersible pump.

Topic contact: Last updated: May 31, 2012