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June/July 2001 |
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Industry News |
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Agreements between Santos Limited and Natural Gas Australia Limited (NGA) have enabled Santos to obtain up to 40% economic interest in the Evans Shoal gas field in the Timor Sea. Located in NT/P 48, approximately 300 km north of Darwin, the Evans Shoal gas field is one of four major Timor Sea fields thought to have a cumulative potential of over 20 Tcf. Recoverable volumes for the Evans Shoal field are estimated at 6.6 Tcf of dry gas and 31 MMbbl of condensate. To obtain the interest, Santos proposes to acquire, by scheme of arrangement, all outstanding shares and options in NGA, whose major asset is a 15% stake in the Evans Shoal gas field. Operator, Shell, holds a 75% interest in the field and Osaka Gas holds the remaining 10%. NGA has also accepted Shell's offer to acquire a 25% interest in the field by exercising its pre-emptive rights. Santos will provide NGS funding of up to US$25 million to acquire up to the offered 25% interest. Santos' Managing Director, Mr John Ellice-Flint, said the acquisition was an important strategic initiative which would facilitate development of a region with immense gas potential. "Natural gas is the fuel of the new millennium and increasingly an internationally traded commodity. The Timor Sea has the potential for a world-class 20 Tcf gas project which would have great benefits for Australia and the new nation of East Timor", Mr Ellice-Flint said. "Santos is supporting this vision by broadening its interests in the region from two to three of the four major fields", he continued. Santos' existing interests in the Timor Sea include an 11.8% interest in the 160 km2 Bayu Undan gas field, with proven plus probable reserves of approximately 3.4 Tcf of gas and 400 MMbbl of liquid hydrocarbons. Santos is also operator of the Petrel and Tern fields in the Bonaparte Basin, with equity interests of 95% and 100% respectively. The Petrel field overlays retention leases NT/RL1 and WA-6-R and the Tern field is located in permit area WA-18-P. Combined proved and probable reserves are in excess of 1 Tcf with significant upside reserves potential in the Petrel field. Timing of the development of the Evans Shoal field will depend on gas demand from existing gas users, fuel switching and commissioning of greenfields projects. Total consideration for a 40% interest is approximately A$80 million, comprising approximately A$30 million equivalent in Santos shares and US$25 million in cash. At a 40% interest, Santos will acquire approximately 2.6 Tcf of gas at an average price of approximately US1.5 cents per thousand cubic feet (mcf), increasing the company's present stake in Timor Sea gas from around 1.5 Tcf to approximately 4.1 Tcf. New 2D Acquisition – Otway/Sorell Basins Seismic Australia Pty Ltd and Fugro-Geoteam AS recently commenced acquisition of the Deepwater Otway/ Sorell 2D seismic survey. The survey is being acquired by Fugro-Geoteam's vessel, Geo Arctic, with 3,660 cubic inch source and 7,000 m streamer. Gravity and magnetic data are also being recorded during the acquisition period. The survey is approximately 6,060 km with the majority of the data located in five of the newly announced 2001 Acreage Release blocks. It is anticipated that processing of the data will be completed and be available for delivery in October 2001.
For
further information please contact either: Further gas discoveries in Victoria are indicative of the ongoing success partners Santos and Beach Petroleum are encountering in their exploration for gas in onshore Australia. Drilled in February this year, McIntee-1 is part of an expanded exploration drilling program for the opening half of 2001. The well has a flow rate of approximately 14 MMcf of gas per day. Following the success of McIntee-1 is Croft-1, the 2529 m deep exploration wildcat well recently drilled in PEP 154. The well is located 7 km southwest of McIntee-1 in the Victorian section of the Otway Basin, 16 km west of the Heytesbury Gas Facility. The third well of a five well program in PEP's 153 and 154, Croft-1 has intersected a 60 m gross gas column in the Cretaceous Waarre Sandstone over the interval 2025 m to 2085 m. Wireline logs are currently being evaluated and indications are of 34 m net gas pay. Commenting, Santos Limited Managing Director, John Ellice-Flint, said, "The well is the fifth Santos operated success in the area and follows on from the recent successes at McIntee 1 and Tregony 1." Reg Nelson, CEO for Beach Petroleum commented, "Beach's earlier discoveries established the Otway Basin as a significant hydrocarbon province. However, the basin proved difficult to explore, largely because it has complex fracture and fault systems in the subsurface rocks. The use of modern 3D seismic has proved to be a breakthrough in providing a clearer picture of the subsurface and for selecting drilling targets with greater confidence." The rig was released from Croft-1and transferred to Lavers-1, the next exploration well in the Otway Basin programme. Located in PEP 154, Lavers-1 is approximately 2 km northwest of McIntee-1. Lavers-1 reached a total depth of 1,627 m and wireline logs were run in early May. Gas shows were encountered over an approximate 10 m gross interval at the top Waarre Sandstone. Santos recorded a further discovery in the area after drilling Naylor-1, located in PEP 154, 3 km northeast of Croft-1. The exploration wildcat well intersected a potential 84 m gross gas column in the Creatceous Waarre Sandstone over the interval 2028 m to 2112 m.
Both Naylor-1 and Croft-1 will be cased and suspended as future gas producers, following evaluation by wireline logs. Jon Young, General manager South Australia Business Unit, said, "With at least 30 m of net gas pay, the Naylor-1 well has the potential to be the most significant discovery in the current Otway exploration program." "This well reinforces our confidence in the future potential of the onshore Otway Basin." The Naylor -1 well is expected to come on production at 10 Tj per day based on an analogy with existing wells in the area. Santos, the operator of Naylor-1, McIntee-1, Croft-1 and Lavers-1, has a 90% interest in each well, and Beach Petroleum the remaining 10%. Santos has had a 100% success rate with their exploration in PEPs 153 and 154. Earlier wells, Mylor-1, Penryn-1 and Fenton Creek-1 are currently on production through the Heytesbury facility. Based on the production of other wells in the area, Croft-1 is expected to come on production at 10 Tj - 15 Tj per day. Drilling of Thylacine-1 in T/30P, has revealed what is expected to be the largest discovery in the Otway basin to date. The well, located 70 km from the Victorian coastline off Port Campbell, revealed a 281 m gas column with potential reserves of 1 Tcf. Drilling operations for the Thylacine-1 are being managed by Woodside, who has a 50 % stake in the project, under an agreement with project operator, Origin Energy, who has 30 % equity. The well was drilled using the Ocean Bounty semi-submersible drilling rig. Commenting on the discovery, Origin's General Manager, Exploration, Dr. Rob Willink said, "Gas in the Thylacine field is trapped in the Waarre Sandstone, a highly productive reservoir that has also been established as gas bearing in the nearby Minerva and La Bella fields, and in a number of small onshore fields in the Port Campbell area." Origin's Managing Director, Mr. Grant King, said, "This is a significant discovery for Origin Energy and the industry in general as it is highly likely to provide an alternative source of gas supply which is close to the eastern Australian gas market and existing infrastructure. The discovery is particularly timely in that a number of large industrial and retail customers in southeast Australia are currently seeking to renew existing contracts, or seek gas supplies for new projects under consideration. Furthermore, this new source of gas dovetails well with our plans to construct a new gas pipeline that will link the Victorian system to Adelaide." Woodside, who is the major equity partner in the discovery, has commenced discussions with potential customers for the sale of its share of gas from the Thylacine-1 discovery. Woodside's Acting Director Australia Gas, Barry Adams, said, "This discovery together with our additional supply options from Greater Sunrise in the Timor Sea and Kipper, Manta and Gummy in Bass Strait fulfills one of the company's key growth objectives of being able to provide gas to all major markets in eastern Australia. "With 50% equity, Woodside has a considerable amount of gas available to sell to the prospective market, and has the potential to provide a long term secure, alternative and competitive source of gas supply to Victoria and South Australia, and meet the states' peak energy demands in the future", Adams said. Interest
holders in T/30P are: Following the completion of the wireline logging program, Thylacine has been cased and suspended for potential completion as a gas producer at a later date. The rig has since moved to drill the Geographe-1 (spudded 30th May) prospect located only some 15 km to the north of Thylacine in adjacent exploration permit VIC/P43. It is approxi-mately 55 km from the Victorian coastline off Port Campbell, in a water depth of approxi-mately 85 m. Origin
Energy Resources Limited and Woodside Energy Ltd have each reached an
agreement with CalEnergy Gas (UK) Ltd to acquire a portion of CalEnergy's
equity in VIC/P43 in return for partial funding of CalEnergy's share of
Geographe 1 well costs. Equity participation after the drilling of Geographe
1, subject to completion of documentation and receipt of regulatory approvals,
will be as follows: Drilling operations for the Geographe-1 well are being managed by Woodside Energy Ltd under an agreement with Origin Energy. In Depth Geophysics Goes Virtual Sydney-based consulting firm In Depth Geophysics has acquired a PC-based seismic interpretation system and is now offering clients an off-site interpretation service. PC-based systems have increased the autonomy of consultants, expanding their role in giving independent advice to the exploration industry. In Depth principal, Ken Grieves, explained that, "By being autonomous, consultants provide a valuable service to the industry, delivering indepen-dent and cost-effective evaluations of prospects, farm-in opportunities and acreage releases." Ken has over 20 years of industry experience, primarily in seismic interpretation. He held positions with GSI and Esso before setting up a consultancy specialising in seismic interpretation and depth conversion. His consulting clients include BHP, Cultus, Esso, Fletcher Challenge, Mosaic, Origin, Petroconsultants, Santos and Vico Jakarta. In addition to offering off-site interpretation and independent evaluations, In Depth will offer a 'second opinion' service. "The industry is still drilling dry holes that could have been avoided if the operator had sought a second opinion on prospect validity, pre-drill", explained Ken. "Given the ease and cost-effectiveness with which a reliable second opinion can now be obtained, I think the industry will move to greater scrutiny of prospect validity, using off-site consultants." "The industry's attitude to off-site interpretation is changing as it becomes easier to move interpretations between sites", added Ken. "The PC-based systems live or die on ease of interpretation exchange between sites. Using a PC system, it is easy to move interpreted horizons, fault segments and so on between sites. An off-site PC interpreter can become a 'virtual geophysicist', interpreting at one site and using the Internet to maintain a parallel interpretation project at the client's site. The parallel interpretation can be updated every week as the project proceeds, allowing the client to monitor progress." In concluding, Ken commented, "This is an exciting new phase for In Depth Geophysics, with opportunities to expand the breadth of its consulting services both in Australia and overseas." Tasmania's Natural Gas Project Fires Up Procedures are underway for Tasmania to receive its first gas supply from the Tasmanian Natural Gas Project in June 2002. Tasmania has relied on hydro-generated electricity to meet varying percentages of its energy needs for over 80 years. In recent years, the state's increasing energy demands and environmental problems that have serious adverse affects on energy supplies, have made the need for supplementary energy sources apparent. In the late 1990s, the state government announced its intention to bring gas to Tasmania and awarded Duke Energy International (DEI) the task of implementation. Recently, DEI signed long term gas supply agreements with Esso Australia and BHP Petroleum (Bass Strait). Tasmania's natural gas supplies will originate in Esso/BHPP's reserves in the Gippsland Basin, from operations that have been supplying gas to Victoria for more than 30 years. The gas composition is approximately 91% methane, 5.3% ethane, 0.5% propane, 0.75% nitrogen, 2.25% carbon dioxide and 0.05% oxygen (indicative). The gas will be processed at the Longford processing plant in Victoria before being transferred to Tasmania, via more than 300 km of subsea pipeline. Esso/BHP, who use the Longford plant to process their Victorian gas supplies, will be increasing the capacity of the facilities in order to meet the additional demands of Tasmania.
DEI recently signed a $100 million agreement awarding OneSteel Market Mills the contract to supply the majority of the 740 km of onshore and offshore steel pipe for the pipeline, although some thicker walled pipe will be supplied by Itochu Pipe Management Australia. The offshore section of the high-tensile steel pipeline will be constructed in 12 m lengths. The finished pipeline will have a maximum allowable operating pressure of 15.3 MPa and be capable of moving 40 PJ of gas per year, although the initial delivery volume will be 20 PJ per year. Pipeline construction is scheduled to start in November 2001. The pipeline will originate at the Longford plant and cover the 27 km onshore to Seaspray on the Victorian coast. The corridor through onshore Victoria makes use of the Esso/BHPP easement for almost the entire length from Longford to Seaspray, and passes mainly through grazed agricultural land. After Seaspray, the pipeline goes subsurface until it comes ashore at Five Mile Bluff in Tasmania, and diverts to the Bell Bay Power Station. Considerations for the subsea section of the pipeline were notably different to those onshore, and included ease of construction, shipping channels, sites of historic shipwrecks, habitats of protected species and communities and compatibility with other planned developments. The seafloor across Bass Strait slopes gradually, but is sufficiently flat to make seabed preparation unnecessary. Five Mile Bluff was chosen as the most appropriate point for the pipeline to come ashore due to its practical positioning - it lies almost directly opposite the pipeline's point of origin on the mainland. Other factors such as the slope, type and extent of rock at the landfall made Five Mile Bluff more favourable than other nearby sites. In later stages of the project, onshore pipelines will be constructed throughout Tasmania. Stage two will see the Bell Bay Power station linked to Port Latta in Tasmania's northwest. The third stage involves construction of a separate pipeline linking Springfield to Boyer and Claremont. Jurisdiction of the onshore sections of pipeline will lie with the Tasmanian government, whereas the majority of the subsea pipeline will come under Commonwealth jurisdiction and, as such, is subject to federal administration procedures. The waters between Tasmania and Victoria are frequented by a wide variety of marine species, some of which are considered endangered, and are thus classed as vulnerable, and protected under Environment Australia's EPBC Act. A number of cetacean species frequent waters near the Victorian coast, the deeper waters of Bass Strait are inhabited by the great white shark and grey nurse shark - both endangered, along with some 28 species of cetaceans that have been observed in the region. The waters off the Tasmanian coast are frequented by a variety of seabirds, whales, dolphins, seals and turtles, who are transients in the area. While Duke has not yet received permits for any part of the project, Alan Sann, DEI's Environment and Approvals Manager for the Tasmanian Natural Gas Project, expects that approvals will be received between August and December 2001. Permits for construction and operation of the subsea pipeline (required under the Petroleum [Submerged Lands] Acts) are expected to come through in or around October. Sann said that DEI had also referred stages two and three of the project (covering the Bell Bay to Port Latta and Rosevale to Hobart onshore sections of the pipeline) to Environment Australia earlier this year. "Both stages have been deemed 'controlled actions' under the Act, on the basis of the proximity of parts of the proposed pipeline to areas of concern from a Commonwealth perspective. A number of bird, crustacean, mammalian and vegetation species were cited by the Minister as reasons for his determination on each of the two stages of the project", Sann said. "Duke believe that the information, arguments and proposed mitigation measures will satisfy these concerns and enable the Minister to make his decision in a timely and positive fashion later this year. He will, under the 2000 Bilateral Agreement between Tasmania and the Commonwealth, rely on the Tasmanian Government's assessment of the specific nature conservation issues cited in his decision", Sann continued. In addition to the pipelines, another major component of the $400 million project is the conversion of the Bell Bay power station from oil-fired to gas. The power station has been a backup for the hydroelectricity scheme in the past. It has been used recently due to the current drought in Tasmania that resulted in insufficient energy generated through the hydroelectric scheme. With the exception of a thermal back-up facility, Tasmania currently depends on the hydroelectric scheme - now operating at close to its peak capacity, to meet its energy needs. An audit by the Tasmanian government concluded that Tasmania's potential for economic growth was limited by the lack of additional energy supplies. Once completed, the natural gas project will eliminate Tasmania's dependency on hydroelectricity and is expected to have a positive effect on the state's economy. Nick Heath, Gas Marketing Director at Esso Australia commented, "Experience tells us that natural gas brings economic growth. Existing Tasmanian industries will become more competitive and new industries will be attracted to Tasmania." The gas supplied by the project will be used initially at Bell Bay for electricity generation, and by large industrial firms in thermal applications. Presently, the home-heating market relies on wood, while the state's industrial sector supplements hydroelectricity with a combination of coal, wood and imported fuels. These methods are costly and have a detrimental impact on the environment. The introduction of gas will reduce the occurrence of localised air pollution, which will be of particular benefit to the Launceston and Hobart regions. Gas is expected to provide a valuable boost to Tasmania's and Australia's exports, with the state's paper and pulp, mineral and wood processing industries expected to expand. The supply of cheaper energy will also result in increased industry activity, particularly amongst those with high energy use or high sensitivity to energy prices. Certain industrial processes that require heat for drying and steam production will particularly benefit from the introduction of gas. A spokesperson at DEI said that the company has already signed contracts with five major clients who are preparing for the introduction of a steady gas supply. Two of these are Australian Bulk Minerals, producers of lead pellets, based in Port Latta, and Hydro Tasmania. The gas supply project has not been without controversy, with some industry members actively debating the chosen gas source and stating that the long-term contract signed with Esso/BHPP will prevent the Island state receiving competitively priced gas. Hobart-based John Davidson, the Australian geologist who was involved with the Yolla discovery in the early 1980s, claimed that sole sourcing the gas from the Gippsland Basin made the project unnecessarily expensive with other alternatives being more viable. He has publicly argued that the Yolla Field, discovered in the 1980s, contains enough gas to supply Tasmania for ten to 15 years, after which time other nearby fields, such as Thylacine (in the Otway Basin), with potential reserves of 1Tcf and Gippsland Basin would be reasonable alternatives. "The Yolla infrastructure would have been the perfect central point for the gas from these three areas", stated Davidson. "Now Tasmania is stuck with a commitment of taking gas from one source for a long period, thus removing any possibility of competition." The Yolla Field is now subject to a $400MM development by Australian Worldwide Exploration (AWE) and CalEnergy Gas (UK) Ltd, who have claimed the field could initially produce a minimum of 20 PJ of gas per annum - approximately 10% of Victoria's current consumption. AWE and CalEnergy have since entered into separate binding Heads of Agreement with Origin Energy Retail Limited for the sale of Yolla gas. A spokesperson at Duke Energy commented that Esso/BHPP were the only clients who adequately met DEI's requirements for long-term reserves (suggested to be a period of 30 years) and could supply competitively priced gas in accordance with DEI's timetable. Duke Energy approached all the existing processors in the region, citing four essential criteria that suppliers needed to meet. The natural gas needed to be competitively priced, available for delivery in 2002 and from a reliable source. The DEI spokesperson said that Esso/BHPP's Gippsland Basin gas operations had considerable reserves, with further exploration in that basin generating increased optimism. DEI's fourth requirement was that the supply was secure. Adele Trend Model Levels Playing Field Activity surrounding WesternGeco's Adele Trend multiclient 3D survey is increasing, as the offshore team commences acquisition of phase-2, and the office-based team aims for firm commitment from clients for phase-3. Data acquisition of phase-1 (by the Geco-Beta towing six 6 km streamers) was completed in May and data will be available to clients by late June. Phase-1 saw Western Geco acquire approximately 2,323 km2 in open acreage, which was put up for gazettal this year, for award next year. The project is being worked in partnership with Seismic Australia who helped identify the area with Geco-Prakla, prior to the amalgamation with Western Geophysical. The phase-1 data was processed using Seismos, Geco-Prakla's proprietary system. Mick Gillespie, Australasian NEPS Manager at WesternGeco, said that data from phase-2, and any future phases, will be processed using Omega, the processing system developed by Western Geophysical, which is now the preferred system for WesternGeco's marine operations. Acquisition of data over the area covered by phase-2 commenced in mid-May, and will be completed by early September. While the current plan is to shoot another 3,144 km2 in phase-2, Gillespie said this may grow in size in accordance with the wishes of a client, who is waiting on the results of a well currently being drilled. "Phase-2 (using the Geco-Resolution towing four 6 km streamers) is being acquired to the southwest of phase-1", Gillespie said. "We're going to do quite a bit of onboard processing to move the process along quickly, and we hope to have a fast track cube that we'll be able to show clients out by Christmas." The parameters for phase -2 will be identical to those in phase-1. "Everything will tie in", Gillespie said. "We're going to tie the lines so it will end up like one large 3D. They're sailing in an east-west direction, using the same guns and the same configuration - 16 guns, 7 second record and a 37.5 m bin. The only thing different will be the onboard processing, which will be using Omega in the second phase." WesternGeco is marketing the data using a new model whose unique features have so far proved popular with clients. "The model is very simple", explained Gillespie. "It allows people to view the data for a nominal fee paid on a monthly basis. There is a minimum of two months to view it and it is for their sole use." "The fee covers all the data collected from the phase and works out at less than a dollar per kilometre to view it. When they've finished evaluating it, they send it back to Western Geco and stop paying", Gillespie added. "We've explained the model to both big and small players. The system ensures an equal playing field: Everyone gets the same data for the evaluation period and each client is entitled to keep any derivatives they get from the data for their sole use. If the client later bids on any of the gazetted blocks there is an additional sum and, if they are awarded a block, they are contracted to purchase the data from WesternGeco. "The deliverables are going to be substantial", Gillespie said. "There's going to be some AVO and other features which have not been offered before. I think it's a very good model and most of the clients we've met agree with us." "There's an early, mid and later evaluation period", he said. "The earlier you come in, the less you pay, but you do not have to take delivery of the goods until you have assembled the team you will have to look at it." "You can pay now and take the data in September, which is a convenient arrange-ment for most companies", Gillespie said. The closing date for bids on the acreage covered by phase-1 is April 11th, 2002, so it is expected that companies would have to take the data before September or October of this year to have time to evaluate the blocks on offer. The possibility of a third phase of the survey, of around 3,000 km2 to the north of the current surveys, is still in the discussion stage and will be dependent on pre-commitments. |
