Australia is making a name for itself as one of the world’s leading LNG producers. According to the U.S. EIA and Australia’s Department of Industry, Innovation, and Science (DIIS), Australia is on track to surpass Qatar as the world’s largest LNG exporter. The commonwealth reportedly already surpassed Qatar in LNG export capacity and exported more than the Middle Eastern nation in November 2018 and April 2019, according to EIA data, Fig. 1.
The country’s LNG export capacity also increased significantly between 2011 and 2019, reaching more than 11.4 Bcfd. EIA reported that Australia’s DIIS forecasted that the nation’s exports will grow to 10.8 Bcfd by 2020-2021, once the recently commissioned Wheatstone, Ichthys and Prelude FLNG projects reach full production.
While several majors, including ExxonMobil and ConocoPhillips, are scaling back in Australia, there are others that are expanding their E&P activity in a country that hopes to maintain its status as the largest LNG exporter in the world. To do this, Australia is working to procure a new flood of investment.
As part of a major LNG capacity expansion, eight LNG export projects were commissioned in Australia between 2012 and 2018. Collectively, the projects—including Pluto, Gorgon, Wheatstone, Ichthys, Prelude, Queensland Curtis, Gladstone and Australia Pacific—export to several countries throughout Asia, where LNG demand is on the rise.
Northwestern Australia. The five projects developed in northwestern Australia—Pluto, Gorgon, Wheatstone, Ichthys and Prelude—have increased the region’s total LNG export capacity to 8.1 Bcfd.
Pluto, which was discovered in 2005 and started production in April 2012, has a 4.3-Mtpa production train. The onshore processing train, operated by Woodside Energy on the Burrup Peninsula, processes gas from two offshore fields—Pluto and Xena. According to Woodside, planning continues for the expansion of Pluto LNG, based on the acceleration of Pluto gas and the potential development of Scarborough gas field via the Pluto LNG facility. Studies reportedly are underway for a potential Pluto-North West Shelf (NWS) interconnector, intended to unlock considerable value for both Pluto LNG and the NWS project. Developing a pipeline connection could aid in the acceleration of Pluto area gas reserves, as well as leverage existing Pluto offshore capacity, Woodside says.
The Gorgon Project is one of the world’s largest LNG developments, and the largest single-resource development in Australia’s history. Situated on the country’s Barrow Island, about 37 mi off the northwestern coastline, Gorgon has become a mainstay for the Australian economy. Total production averaged 2.6 Bcfd and 18,000 bcpd during 2018. It includes an LNG facility with three processing units designed to produce 15.6 million metric tons of LNG every year. The project achieved first gas in March 2016, positioning Chevron to become one of the world’s biggest LNG suppliers by 2020. By March 2017, Gorgon’s Trains 1 and 2 were producing approximately 230,000 boed of LNG and domestic gas, according to Chevron. The third train started that same month.
Chevron Australia and its JV partners announced in 2018 that there would be continued offshore development at Gorgon. Phase 2 of the development plan includes the expansion of the subsea gas gathering network, which already consists of 20 subsea structures, 63 spools, and about 500 mi of pipeline and associated infrastructure. In addition to the project’s offshore production pipelines and subsea structures, a number of new wells are planned for Gorgon and Jansz-Io fields. Drilling reportedly began in June 2019.
“The Gorgon and Wheatstone Projects, combined, have injected more than $60 billion in local content into the Australian economy over their construction phases,” said Nigel Hearne, managing director at Chevron Australia.
Chevron’s Wheatstone project achieved first LNG production in early October 2017. Also situated on Australia’s western coast, about 7.5 mi west of Onslow, Wheatstone processes natural gas from Wheatstone and Iago fields. The project, at full capacity, will supply approximately 8.9 million metric tons per year to customers in Asia.
Just one year into its expected 40-year lifespan, Inpex’s $45-billion Ichthys project is expected to produce 8.9 million tonnes of LNG (per annum) and more than 100,000 bcpd at peak. The field, which Inpex calls one of “the most significant oil and gas projects in the world,” started production in July 2018 and is estimated to contain more than 12 Tcf of gas and 500 MMbbl of condensate in the Browse basin, off Australia’s western shore. It is nearly 510 mi southwest of Darwin and covers an area of 800 km2, in water depths averaging about 820 ft.
According to Inpex, it is one of the few energy projects worldwide to incorporate the whole chain of development and production—subsea, offshore, pipeline and onshore. It utilizes an onshore processing site, as well as a central processing facility, the Ichthys Explorer CPF (Fig. 2), which is the largest semisubmersible in the world and the first to operate in Australian waters. It also employs the Ichthys Venturer FPSO (Fig. 2) and a 553-mi gas export pipeline.
Also in the Browse basin, Shell’s Prelude FLNG facility, situated approximately 295 mi northeast of Broome, delivered its first LNG shipment in June. Prelude started production during December 2018. Gas was promptly introduced onboard that June. The facility is about 1,601 ft in length and more than 242 ft wide. According to Shell, the vessel was designed to stay moored in the field for a minimum of 25 years.
In October, ConocoPhillips offloaded its northern Australia businesses, which included operating interests in the Darwin LNG processing plant and the Bayu-Undan, Barossa and Poseidon gas fields. The firm agreed to sell its interests to Santos Ltd. for $1.4 billion. The deal followed Santos’ $2.15-billion acquisition of Quadrant Energy in 2018, as the company continues to expand its position in the region in hopes of becoming Australia’s top independent energy producer.
Eastern Australia. To the east, in Queensland, the Queensland Curtis, Gladstone and Australia Pacific projects were completed, bringing the region’s nameplate capacity to more than 3.4 Bcfd. Shell’s Queensland venture (QGC) produces LNG via a two-train LNG liquefaction plant on Queensland’s Curtis Island. Additionally, it produces natural gas from more than 2,600 production wells, 24 field compression stations, six central processing plants and two water treatment plants in the Surat basin of southern Queensland. According to Shell, the JV supplies more than 10% of east coast gas demand and 40% of Queensland demand. The project has delivered more than 500 cargoes of LNG to customers, to date.
Likewise, the Gladstone LNG (GLNG) project—which incorporates the development of resources in the Surat and Bowen basins in southeastern Queensland—employs a more-than-260-mi underground gas transmission pipeline and a two-train liquefaction and storage facility, also on Curtis Island, Gladstone, Queensland. Santos operates the project, which saw first production in September 2015. The company says it is now focused on extracting value from its established infrastructure and building gas supply by drilling new wells in an effort to increase production.
Australia Pacific LNG—a JV consisting of ConocoPhillips (37.5%), Origin Energy (37.5%) and Sinopec (25%)—shipped its first cargo of LNG in January 2016, after nearly five years of development and construction. The facility features two processing trains, each with a nameplate production capacity of 4.5 Mpta. Conoco is operator of the Australia Pacific LNG export facility, which was not part of its northern Australia divestment deal with Santos.
In September, ExxonMobil announced that it was putting its entire Gippsland basin upstream portfolio up for sale in southeastern Australia. “As a pivotal producer on the east coast, [these] assets play a key role in supplying gas to Australia’s biggest market. As such, we would expect interest to be strong from domestic players that wish to gain greater exposure to rising gas prices, of which there are a significant number,” Wood Mackenzie Research Director Angus Rodger said in a release.
Norwegian E&P company Equinor made momentous progress recently, after being granted approval by Australia’s offshore petroleum regulator for exploration drilling in the Great Australian Bight, on Australia’s southernmost coastline. The area, which has seen little exploration until now, is believed to hold approximately 1.9 Bbbl of oil or more. “If the exploration is successful, there are significant economic benefits in an environment where Australia’s oil production has been declining,” Matthew Doman, director of external affairs at the Australian Petroleum Production & Exploration Association, told Bloomberg.
Equinor plans first to drill the Stromlo-1 exploration well in Exploration Permit 39 (EPP39). The well will be situated in the Ceduna sub-basin, off South Australia. It will be approximately 248 mi southwest of Ceduna and about 295 mi west of Port Lincoln, in water depths of approximately 7,349 ft, Fig. 3.
According to the company, Stromlo-1 will not be cored or production-tested for hydrocarbons in the event of a discovery. Instead, it will be permanently plugged and abandoned, and results will be evaluated prior to determining whether or not to proceed with appraisal or further exploration drilling. Drilling is not scheduled to begin until late 2020, however.
Santos reported flow test results for its Dorado-3 appraisal well offshore Western Australia in October. The 171 MMbbl of oil discovered at Dorado is reportedly one of the largest oil resources ever found on Australia’s North West Shelf (NWS). Dorado-3 confirmed that the Caley reservoir’s main pool is capable of producing flowrates at the high end of pre-drill expectations. The initial clean-up flow test of the reservoir, which is situated in petroleum permit WA-437-P in the Bedout basin, reportedly was conducted over 12 hr, achieving a maximum measured rate of approximately 11,100 bopd and 21 MMscfd of associated gas through a 68/64-in. choke. According to the company, this was the highest rate ever to be recorded from an NWS appraisal well test.
“The results are very encouraging for development of the shallow-water Dorado field, with the test indicating very high potential flowrates of around 30,000 bpd from each single production well in the Caley reservoir. This positive result represents a significant step in progressing Dorado as one of Santos’ most exciting new development projects,” said Santos Managing Director and CEO Kevin Gallagher in a release. The Caley flow test was the second of two at Dorado field. It was drilled with the Noble Tom Prosser jackup, in water depths of approximately 311 ft, reaching a total MD of nearly 15,233 ft. It followed the Baxter test, which reportedly confirmed excellent productivity and fluid quality. With positive results from both tests, the company said that it supports progress toward FEED entry early this year.
Also anticipated for this year is a final investment decision from Woodside on its Scarborough project, in the Carnarvon basin. Estimated to hold 13 Tcf of dry gas, the Greater Scarborough fields include Thebe, Jupiter and Scarborough. According to the company, it is proposing the initial development of the 11.1-Tcf Scarborough resource through seven subsea wells that will be tied back to a semisubmersible. Gas would then be transported via a 270-mi pipeline to the existing LNG infrastructure on the Burrup Peninsula. The company says that its preferred concept for Scarborough is to tie it in to a brownfield expansion of the Pluto LNG facility.
Onshore. Santos is progressing onshore in Australia, receiving approval for the country’s first Environmental Management Plan for onshore shale gas exploration in the Northern Territory since the moratorium was lifted in early 2018. Approval for the Tanumbirini 2H and Inacumba 1/1H wells was awarded in July. The wells are to be drilled in Exploration Permit 161 in the McArthur basin, east of Daly Waters. “We drilled Tanumbirini-1 in 2014 and liked what we saw, so we are delighted to be in a position to resume exploration drilling,” Gallagher said in a release.
Also in South Australia, the state government recently offered five new petroleum exploration licenses in the Cooper basin (Fig. 4) and three new licenses in the Otway basin for bid. On the Cooper basin blocks, 11 wells reportedly have been drilled, and a total of 6,078 line km of 2D and 407 km2 of 3D seismic data have been acquired there.
Likewise, on the Otway basin acreage, 39 wells have been drilled, and a total of 8,842 line km of 2D and 171 km2 of 3D seismic data have been acquired. According to a release, the various blocks offer a diversity of play types and the opportunity to build a portfolio of prospects and leads across the region.
In announcing that firm’s half-year results for 2019, Santos’ Gallagher said, “In the Cooper basin, our focus on low-cost, efficient operations contributed to stronger first-half production and the highest number of wells (51) drilled in 12 years. The Cooper basin is now positioned to grow production and reserves.” The firm said that it anticipated drilling approximately 105 wells in the region for the entire year.
On Nov. 10, 2019, Santos celebrated “50 years of safely and sustainably delivering natural gas” from its foundation asset, the Moomba processing plant in the Cooper basin. It was on Nov. 10, 1969, that the very first molecules of gas arrived in Adelaide via the 800-km pipeline from Moomba. From those modest beginnings, Moomba has become a critical hub in the eastern Australian energy market, connecting Queensland, New South Wales and Victoria via a network of pipelines built since.
Santos’ Gallagher said, “The arrival of much-cleaner natural gas helped transform South Australia’s economy, providing a secure and reliable source of energy for homes and industry, and Australia’s first, and to this day, largest natural gas-fired power station at Torrens Island. Today natural gas remains crucial, if we’re to solve the twin challenges of reducing carbon emissions while meeting growing demands for secure and reliable power generation, supporting the integration of renewable energy into the grid.” Gallagher also noted that 2019 marked Santos’ 65th birthday.
PAPUA NEW GUINEA
North of Australia, Papua New Guinea (PNG) has been a primary focus for Total. The company, alongside its JV partners, Exxon Mobil and Oil Search Ltd., was swept into a lengthy negotiation with the country’s government regarding the Papua LNG project, in PNG’s Gulf Province, early last year. The project’s progress ceased after a new government, led by Prime Minister James Marape, came into power in May. Marape pledged better resource deals in the country, sending the multi-billion-dollar development plans into an abrupt standstill.
Since then, however, the project has been given the green light, and Total reportedly is moving forward with its FEED stage. The $10-billion project to build 5.4 Mtpa of capacity reportedly will consist of two trains of 2.7 Mtpa capacity, each, and unlock over 1 Bboe. The LNG plant is anticipated for development in conjunction with Exxon-operated PNG LNG, through an expansion of the existing plant in Caution Bay.
It was reported in September that PNG would push for further negotiation regarding Exxon’s P’nyang gas project, as well. P’nyang is expected to help feed the expansion of the PNG LNG plant. “We look forward to working with the government of PNG to progress the required gas agreement for the P’nyang project ahead of potential decisions on FEED for the three-train development at the existing LNG plant site,” Exxon told Reuters in September.
For its part, Santos stressed that its presence in PNG features continued strong production at PNG LNG, together with an “aligned acreage position” in the highly prospective region. The company noted that continuous optimization of the facilities has resulted in record daily rates greater than 9 Mtpa, on an annualized basis. Santos took a step toward expanding its presence by signing a binding letter of intent last year to acquire a 14.3% interest (pre-government back-in) in the P’nyang (PRL 3) license. As of fourth-quarter 2019, the company was working with JV partners and the PNG government to finalize the farm-in and gas agreement. P’nyang field has a certified gross 2C contingent resource of approximately 4.4 Tcf of natural gas.
Muruk-2 appraisal. In November 2018, Oil Search and five partners spudded the Muruk 2 appraisal well in PDL 9, in the Southern Highlands of PNG, approximately 11 km northwest of the Muruk 1 gas discovery, Fig. 5.
Oil Search said that the objective of Muruk 2 was “to constrain the potential resource volumes in the field.” On May 2, 2019, the operator said that it had plugged Muruk 2 after an extended testing program, and demobilized the rig.
“During the month,” said Oil Search, “the Muruk 2 well was tested, confirming gas in pressure communication with Muruk 1 ST3. The well flowed at a maximum rate of 16.5 MMscfd on a 52/64-in. choke. This was impacted, as expected, by drilling-induced formation damage, caused by mud and other fluid losses into the reservoir, which materially reduced flowrates. Pressure gauges were installed downhole to monitor the well during the pressure build-up phase. This would assist in evaluating the contingent resources in Muruk field, which is only (a max of) 20 km from existing infrastructure at Hides.”
Nevertheless, in its “Santos 2019 half-year report,” Santos remarked that at the Muruk 2 appraisal, “a significant gas resource was confirmed 21 km northwest of the Hides production facilities.” Indeed, in its Third-Quarter Activities Report of 2019, Santos commented further, stating that “long-term pressure build-up monitoring continues at the Muruk-2 appraisal well. As previously reported, results from the drill stem test confirmed the presence of gas in the Toro A reservoir, with pressure data and gas composition informing volumetric estimates and establishing a likely connection to the Muruk-1 discovery.”
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