Australia takes the lead as top LNG exporter, but will it last?
For years, Australia’s overall production rate has been shrinking. However, according to the U.S. EIA, additional production from new condensate and crude oil developments is expected to offset the decline over the next few years. After peaking around 828,000 bpd in 2000, Australia’s total liquids production decreased to an estimated 387,000 bpd in 2016.
Nonetheless, Australia still holds a surplus of energy commodities. In 2015, it was the world’s largest coal exporter and the second-largest exporter of LNG, according to EIA. It’s energy exports account for approximately 39% of its total export revenues. Australia is attractive to foreign investors, not only because of its substantial hydrocarbon reserves, but also because it maintains a stable political environment and is in close proximity to Asian markets, where demand is high.
In November, Australia surpassed Qatar as the world’s largest exporter of LNG. During that month, Australia reportedly loaded 6.5 million tons of LNG for export. The surge in Australian exports is credited largely to the start-up of several key projects, including the most recent start-up of the Ichthys project.
Several significant projects are underway offshore Australia. They feature considerable technical innovation.
Ichthys LNG. The Ichthys project lies offshore Australia’s northern coast and consists of Ichthys gas and condensate field, a 552-mi gas pipeline, and an onshore LNG plant near Darwin, in the Northern Territory. The project’s offshore facilities include a subsea well development connected to a central processing facility for gas treatment, and an FPSO vessel (Ichthys Venturer) to which the condensate is produced. According to Total (30% stakeholder), the project’s offshore facilities will produce about 285,000 boed and 85,000 bcpd at full capacity. The gas is being exported to the onshore LNG plant near Darwin, where approximately 8.9 million tons of LNG will be supplied to the Asian market every year.
In late July, Total announced that the more-than-$40-billion project put its first production well online. By October, the first cargo of condensate was shipped to Asia. The first LNG shipment followed just a few weeks later. According to operator INPEX, approximately 70% of LNG produced by the Ichthys project will be shipped to Japan over the course of its operational lifetime—which is expected to be about 40 years.
Prelude FLNG. Shell’s first-of-its-kind FLNG, Prelude, floating 124 mi off Australia’s northwestern coast, is expected to revolutionize the way that gas resources are developed. The project not only features the world’s first FLNG, but it also is the largest offshore facility ever constructed, according to the company. It is 1,601 ft long, 243 ft wide, and was constructed with more than 260,000 tons of steel.
Although it is one of seven export projects to be sanctioned in Australia during the last decade, it is unlike any of the others. The project’s equipment—including power generation, gas processing and liquefaction—is contained on the colossal floating platform that is connected to wells more than 820 ft below the sea’s surface.
In June of last year, Shell reported that hydrocarbons had been flowed onboard for the first time. According to the company, LNG is carried through process equipment and pipework before it is stored in tanks found in the facility’s hull. Four of the LNG tanks, which hold 39,000 m3, each, are already full, Shell said in a release.
West Barracouta. ExxonMobil reached FID on its West Barracouta gas field this past December. The project—situated on the VIC/L1 Block, offshore Victoria, in the Bass Strait—will see development of one of the largest remaining sweet gas reservoirs in the area, through a two-well brownfield tie-back to an existing Gippsland basin JV infrastructure. The Gippsland basin, offshore southeastern Australia, is one of the country’s oldest, most important areas for E&P.
“The Gippsland basin Joint Venture has 50 years of experience in Bass Strait,” ExxonMobil Australia Chairman Richard Owen said in a release. “Since the first Bass Strait well was drilled in 1965, about 4 Bbbl of crude oil and 8 Tcf of natural gas have been produced.”
The Gippsland basin JV—which is a 50-50 joint venture between ExxonMobil and BHP—supplies approximately 40% of east coast Australian domestic gas demand. Graham Salmond, general manager of BHP Petroleum Australia, said, “The West Barracouta project is an important investment, underpinned by strong economics and rates of return that will unlock a high-quality, new gas resource and help offset Bass Strait production decline at a vital time for the east coast market.”
The JV has invested more than $4 billion in new projects in Victoria, to help meet Australian domestic gas demand. The partners expect to see production from West Barracouta by 2021.
Dorado-1 discovery. Last July, Santos Limited (operator, 80%) and Carnarvon Petroleum (20%) reported a significant oil discovery in the Caley Member within the WA-437-P offshore exploration permit, in the shallow waters of Australia’s Northwest Shelf. The Dorado-1 well not only confirmed a hydrocarbon column in the Caley Member, but also confirmed the presence of gas and condensate in the top of the Baxter Member.
The company reported that while drilling through the Caley Member, LWD tools indicated a sandstone reservoir section with elevated gas readings and increased resistivity. Light oil was recovered from a sand in the upper-most section of Caley. Likewise, further reservoir sands were encountered in the Baxter Member, with accompanying indications of hydrocarbons. The well was drilled to approximately 13,290 ft, MD, and reportedly had yet to encounter water-saturated sands.
Carnarvon had estimated in April that there was a possibility for the structure to contain resources of approximately 545 Bscf of gas and 125 MMboe. The company’s 2019 drilling program reportedly will include two Dorado appraisal wells that will focus on gaining further information on the volume of oil, gas and condensate in the Dorado-1 well to build proved reserves; determine the flow properties of hydrocarbons from the reservoirs intersected; and obtain additional data at different locations within the field. In December, the Noble Tom Prosser jackup was secured to drill the appraisal wells, Fig. 1.
“The objective in 2019 is to enhance our understanding of the volume of the resources recoverable and move to making a Final Investment Decision for development, ideally in 2020,” Managing Director Adrian Cook said in a release.
North West Shelf Project. Delivering a third of Australia’s oil and gas is Woodside’s North West Shelf (NWS) Project, also off the country’s northwestern coast. According to Woodside, it is the largest producer of domestic gas for Western Australia.
The A$34-billion project has been in operation for 35 years. NWS assets consist of the Karratha gas plant (KGP), about 783 mi north of Perth; the North Rankin Complex (North Rankin A and B platforms), situated nearly 84 mi northwest of Karratha; the Goodwyn A platform, about 14 mi southwest of North Rankin A; and the Angel platform, nearly 75 mi northwest of Karratha.
KGP features an export capacity of 16.9 MTPA. It has five LNG processing trains, two domestic gas trains, six condensate stabilization units and three LPG fractionation units. Additionally, the NWS project includes the Okha FPSO vessel, which is moored to a riser turret approximately 21 mi east of the North Rankin Complex.
Scarborough development. Woodside started awarding contracts for the proposed Scarborough development, offshore Western Australia, in August. The field is in the Carnarvon basin, about 233 mi northwest of the Burrup Peninsula. Scarborough is estimated to contain approximately 7.3 Tcf of dry gas.
According to Woodside, the proposed development will comprise 12 subsea, high-rate gas wells tied back to a semisubmersible floating production unit, moored in nearly 2,953 ft of water near Scarborough field. The company plans to transport gas via a 267-mi pipeline to existing LNG infrastructure (Pluto LNG expansion) on the Burrup Peninsula.
With LNG capacity of 4.9 Mtpa, Woodside’s Pluto LNG processes gas from Pluto and Xena gas fields, offshore Western Australia. Gas from these fields is transported to a single onshore LNG processing train. However, with the potential development of Scarborough gas field, Woodside reportedly is planning an expansion of the facility.
Gorgon LNG. Also off the coast of Western Australia, the Chevron-operated Gorgon project is of great significance. Not only is it the largest single resource project in Australian history, but it also is one of the largest LNG projects in the world.
Approximately 37 mi off Australia’s northwestern coast, on Barrow Island, the Gorgon project consists of a three-train, 15.6-Mtpa LNG facility and a domestic gas plant with the capacity to supply 300 terajoules of gas per day (284.3 MMcfd) to Western Australia. Additionally, Gorgon can produce 20,000 bcpd.
The project’s offshore facilities include 18 high-rate, big-bore development wells—eight of which are at Gorgon field, and 10 of which are at Jansz-Io field.
A subsea gathering system is affixed to the seafloor, collecting from both Gorgon and Jansz-Io fields. Gorgon field can be found about 40 mi west of the island, while Jansz-Io field is situated more than 80 mi northwest of the island, in deeper waters. According to Chevron, the gathering system utilizes 18 subsea trees to contain and control production wells at both fields. The gas is then transported via pipeline to Barrow Island.
Wheatstone LNG. Likewise, Chevron’s Wheatstone LNG is a significant project for the Australian energy sector. The project is one of the country’s largest resource developments, and it is Australia’s first major gas hub. It consists of two LNG trains, with combined capacity of 8.9 Mtpa, as well as a domestic gas plant, nearly 7.5 mi west of Onslow, in Western Australia.
The offshore platform is one of the largest in Australia, standing approximately 700 ft tall. It rests on a steel substructure in about 230 ft of water. Natural gas is carried from the platform to the onshore plant via a 140-mi pipeline.
Australia’s onshore E&P activity is concentrated primarily in the Cooper basin, in the eastern part of the country. According to EIA, production from this region has doubled since 2010 and accounts for approximately 11% of Australia’s oil production.
Cooper basin. Santos has been making significant progress at several of its onshore assets. In August, it reported that a fourth rig, the Ensign 965, had begun drilling operations in the Cooper basin. According to the company’s report, the rig would drill eight new wells in Big Lake field by year-end, before moving to Moomba South, where it would drill four appraisal wells. The company said that the fourth drilling rig would allow it to drill up to 90 wells in 2018, which reportedly is the most wells drilled in a single year since 2014.
“As Santos has become Australia’s lowest-cost onshore natural gas developer, reducing development well costs by more than 40% in the Cooper since 2015, we now have the right cost base to invest in making the most of the vast discovered resource base of Cooper basin natural gas,” said Santos Managing Director and CEO Kevin Gallagher in a release.
The Cooper basin—which covers approximately 127,000 km2 (49,035 mi2) extending across the northeastern part of South Australia—has been producing for more than 50 years. Senex Energy is another Australian E&P company that invests heavily in these resources.
Senex successfully completed an initial flow test of the Gemba-1 exploration well, in the Cooper basin, in December. The well was drilled on the southwestern margin of the Allunga Trough, nearly 23 mi southwest of the Moomba processing facility, north of Adelaide.
Prior to the flow test, Senex had successfully completed a seven-stage hydraulic fracturing program across depths of 2,360 to 2,730 m (7,146 to 8,957 ft). The company proceeded with a seven-day flow test, which subsequently recovered 44 MMscfg and 88 bbl of liquids. Senex reported that a stabilized flowrate of ~8 MMscfd was achieved.
Senex said that preliminary interpretation of volumes indicated pre-drill estimates of 15 Bcf of ultimate gas recovery, which could be exceeded. This year, the company plans to move forward with an extended production test across each of the discovered intervals to further assess the reservoir, deliverability and ultimate recovery of each zone. It anticipates first gas sales by year-end.
Surat/Bowen basins. Senex Energy also made progress in Queensland during October, when the company reported FID for two natural gas projects in the Surat basin. The more-than-$200-million developments, Project Atlas and Roma North, will see the drilling of a combined 110 wells at the outset, two gas processing plants, and associated pipelines and facilities. Both developments are in close proximity to existing infrastructure, as Project Atlas is just 12 mi southwest of Wandoan, and Roma North is approximately 18 mi north of Roma. Beginning at the end of first-quarter 2019, development is expected to continue for about 18 months, the company reported.
Santos also has a position in the Surat and Bowen basins, in Queensland. In a 50-50 joint venture with Shell, Santos was designated the operator of new exploration acreage in November. The PLR201718-2-5 license covers about 400 km2 (154 mi2), approximately 12 mi east of the town of Surat. The area reportedly was released by the government, solely to boost domestic gas supply on Australia’s east coast.
According to Santos, exploration in the new acreage will target natural gas in the deep sandstone reservoirs of the Bowen basin, beneath the Surat basin. If drilling yields positive results, a new gas supply source could be unlocked for Australia’s east coast domestic gas market.
PAPUA NEW GUINEA
Despite a brief setback last year, Papua New Guinea (PNG) remains a competitor in the oil and gas sector of the South Pacific region. Last August, Santos reported a significant natural gas find in the Forelands region. The Barikewa-3 well reportedly encountered 82 ft of net gas pay in the Toro and Hedinia reservoir objectives. “The Barikewa-3 result is encouraging and confirms that there are significant natural gas resources close to PNG LNG infrastructure, still to be developed,” Gallagher said. “Barikewa is located approximately 10 km from the PNG LNG gas pipeline and is, therefore, well-placed to play a part in future LNG expansion projects.”
PNG LNG. ExxonMobil’s $19-billion PNG LNG project is the largest development ever undertaken in PNG. Its production facilities are spread out across three provinces, with two processing facilities connected via a nearly 435-mi pipeline network. In 2017, alone, PNG LNG produced 8.3 million tons of LNG to its Asian customers.
Production was disrupted last year, however, when a major earthquake rocked the country’s oil and gas sector. The destructive 7.5-magnitude quake triggered landslides, destroyed buildings and killed more than 100 people. PNG LNG operations were completely shut in for a period of time, as damage was assessed.
Just a few months later, ExxonMobil announced a significant increase in resources at P’nyang field, in PNG’s Western Province. The company reported an 84% increase, to 4.36 Tcf of gas, from its previous assessment. The company, and its JV partners—Oil Search, Kumul Petroleum Holdings, Santos, JX Nippon Oil & Gas Exploration and Mineral Resources Development Co.—reported that the results support plans for a three-train expansion for PNG LNG, near Port Moresby.
According to Exxon, one new train will be dedicated to gas from P’nyang and PNG LNG fields, while the other two trains will be dedicated to gas from the Papua LNG project. The expansion reportedly would add about 8 million tons of LNG annually, doubling the plant’s existing capacity.
Papua LNG project. In November, Total and its partners, ExxonMobil and Oil Search, signed an MOU with PNG for the Papua LNG project. The project, first proposed in 2015, should see the development and commercialization of the Elk-Antelope resource in PRL 15 (Fig. 2), situated in the New Guinea Fold Belt, Papuan basin.
The project will include two LNG trains of 2.7 Mtpa, each. They are expected to be developed in cooperation with the existing PNG LNG project facilities. The project partners already have launched the first phase of engineering studies, and they reportedly expect to see FID this year.
- Applying ultra-deep LWD resistivity technology successfully in a SAGD operation (May 2019)
- Adoption of wireless intelligent completions advances (May 2019)
- Majors double down as takeaway crunch eases (April 2019)
- What’s new in well logging and formation evaluation (April 2019)
- Qualification of a 20,000-psi subsea BOP: A collaborative approach (February 2019)
- ConocoPhillips’ Greg Leveille sees rapid trajectory of technical advancement continuing (February 2019)