Not so long ago, people thought the Cooper Basin was dead.
Australia’s largest onshore hydrocarbon resource had supplied almost 170 Bcm (6 Tcf) of natural gas to homes and businesses across a wide swath of southern and eastern Australia, but after 40 years some people thought it was on its last legs. Others had more faith, and now the believers have been proven right.
The Cooper Basin is entering a renaissance, driven by escalating domestic gas demand and the voracious appetite of three new LNG plants in Queensland.
It was New Year’s Eve 1963 when the Cooper Basin was born. At 6 a.m. the Gidgealpa-2 well struck gas in the sandy wilderness of the South Australian outback. A plane bringing supplies to the isolated rig from Adelaide, 800 km (497 miles) to the south, was promptly recalled and filled with as many bottles of champagne as it could hold, and South Australia’s first hydrocarbon discovery was celebrated with gusto.
The discovery was made by Adelaide-based Santos in partnership with Delhi Petroleum, owned by Texas oil baron Clint Murchison. Santos owned the acreage, and Delhi provided funding, operatorship and experience to the then-fledgling Australian company. Further drilling soon confirmed a medium-size gas field at Gidgealpa, but it wasn’t until the discovery of the much-larger Moomba Field in 1966 that a commercial volume of gas was assured.
By then, British oil giant Burmah Oil Co. had joined the partnership, bolstering Santos’ technical expertise and providing valuable direction for construction of the gas processing plant at Moomba and the pipeline to Adelaide. It also offered commercial advice for contract negotiations with the fi rst industrial customers—the South Australian Gas Co. and the Electricity Trust of South Australia.
Burmah’s leadership—in conjunction with Delhi’s initial failure to detect hydrogen sulfi de (H2S) in the Cooper Basin gas, leading to expensive design modifi cations at the gas plant—resulted in Santos gaining operatorship of the Moomba plant in 1971, which it has retained since. Delhi continued as exploration and field production operator in various roles until Santos finally took over all Cooper Basin operations across Queensland and South Australia in 1992.
Still going strong
That was then; this is now. “The Cooper Basin remains a valuable producing asset for Santos,” said Lou Dello, Santos’ general manager for Central Australia. “The Cooper Basin is far from decline, and we have seen strong growth in conventional 2P reserves since 2010.”
He highlighted underexplored greenfield potential in southwest Queensland, significant gas-in-place resources in greater Tindilpie, the liquids-rich northern fields in South Australia and further development opportunities at Moomba and Big Lake.
In 2014 the Cooper Basin produced 16.2 MMboe, approximately 30% of Santos’ total production. Of this production, 20% came from oil, 67% from gas and the remainder from condensate and LPG.
In the current environment of constrained world oil prices, activity in these jointly held areas is focused on maximizing efficiencies and operating only the best wells across the basin’s 190 gas fields and 115 oil fields, Santos CEO David Knox told shareholders at the company meeting in April. Those fields contain about 820 producing gas wells feeding into production facilities at Moomba in South Australia and Ballera in Queensland for gas sales to Sydney, Adelaide, Mount Isa and Brisbane.
Ethane is piped to the Qenos petrochemical plant in Sydney, while gas liquids, condensate and oil from the more than 400 producing oil wells are piped to wharf facilities at Port Bonython near Whyalla, South Australia, for export.
Demand for gas is expected to triple in the next few years as New South Wales sales contracts expire and LNG plants on the Queensland coast at Gladstone ramp up to full production. Santos is buying 20.2 Bcm (714 Bcf) of Cooper Basin gas from its so-called Horizon portfolio to help fuel its Gladstone LNG (GLNG) plant, while Beach Energy is selling gas to Origin Energy for its Australian Pacific LNG (APLNG) plant.
“GLNG has facilitated the development of our coalseam gas fields in Queensland, but it also has been an essential catalyst for the development of our wider east coast resources,” Knox said.
“It has exposed the Cooper Basin to new markets, which has made continued development of the Cooper viable,” he added. “If Santos had remained as heavily focused on the domestic market as it was just 10 years ago, those resources would not be commercially viable today. Higher gas prices lead to higher investment and ultimately production. And that is what is happening in the Cooper today.”
After the gas discoveries of the 1960s and 1970s and the oil boom of the 1980s, it is the rise of the unconventionals that will take the Cooper Basin into the new millennium and beyond. Deep coals, tight sands and shales are all being investigated in the new wave of exploration.
In 2012, 46 years after the Moomba-1 gas discovery of 1966, the first commercial shale well in the Cooper Basin commenced production. Moomba-191 is flowing natural gas at a rate of 48 Mcm/d (1.7 MMcf/d) from the Roseneath, Epsilon and Murteree shale rock, with a composition consistent with gas produced from the Moomba/Big Lake area. Santos currently has three unconventional shale wells in production.
“Although it is still early days, Santos is encouraged by the potential of unconventional resources in Central Australia,” Carl Greenstreet, Santos’ general manager of unconventional resources, said.
“Across the Cooper Basin in South Australia and southwest Queensland and in the Amadeus Basin and McArthur Basin in the Northern Territory, we have 100,000 sq km [38,610 sq miles] of highly prospective acreage in unconventional gas plays.”
However, with world oil prices at a six-year low, much of the unconventional resources program has been put on the shelf. Despite the great gas potential in the Cooper Basin, it is a time of belt-tightening and protecting finances until economic conditions improve.
“I do believe it will be developed; it’s just going to take some time, and we’re not going to rush out in this environment and spend all of our equity dollars,” said Chris Jamieson, Beach Energy’s group executive of external affairs.
Beach Energy is exploring tight gas acreage in the Nappamerri Trough with permits covering more than 800,000 acres stretching across the South Australia/Queensland border. Despite the disappointment of Chevron exiting the partnership in March, Beach and junior partner Icon Energy (which holds a 35.1% interest in Queensland permit ATP 855) are upbeat about the future opportunities.
“During the past three years the joint venture flowed natural gas from four wells, achieved the highest flow rate from a shale gas well [Halifax-1] in the Cooper Basin, had six petroleum discoveries in ATP 855 and has identified a significant natural gas resource within the Permian formations of the Nappamerri Trough,” said Icon Energy Managing Director Ray James.
Chevron plowed $330 million into the program, which has uncovered 2C contingent gas resources of 45 Bcm (1.6 Tcf) in the Queensland permit. Beach also is exploring in South Australian permits PRL 33 and PRL 49, with 18 wells drilled across the entire trough to date.
“We’ve had some really good results,” Jamieson said. “There’s potentially a massive gas resource there. However, it’s challenging. It’s not low-hanging fruit.
“These formations are 3 km to 4 km [1.9 miles to 2.5 miles] down,” he continued. “It’s deep, it’s hot and it’s high-pressure. However, the coring that we’ve done has shown that there’s a lot of gas down there. And we’ve flowed gas, which has been a big tick in the box.
“Now it’s a matter of drilling and completing these wells efficiently and more cheaply and fracture-stimulating in a way that will generate commercial-style flow rates,” he added.
New technologies and industry developments will continue to assist the drive for unconventionals in the Cooper. Innovations in fracture stimulation such as electrical pulsing and low fluid volumes also will help unlock hydrocarbons from the deep coals of the Patchawarra Trough and the southern Cooper Basin being targeted by all of the major Cooper Basin players as well as smaller companies such as Senex Energy and Strike Energy.
Santos’ Tirrawarra South-1, the first dedicated deep coal producer, is expected online in the next few months for long-term production monitoring.
Meanwhile, Beach Energy is confident of finding a new partner to join its Nappamerri Trough program once the Stage 1 data have been analyzed.
“We want to make sure we’re fully across all the data and make sure that we’re in the right position in terms of the next stage,” Jamieson said. “We’re still confident that this area will be developed at some stage; it’s just a matter of when. Whether it’s five years’ time or whether it’s 20 years’ time, we’re confident it will be developed.”
Changing interests in Cooper Basin
The Cooper/Eromanga Basin has seen myriad joint-venture (JV) partnerships. Santos secured the original leases and has always kept the lion’s share, with Delhi Petroleum being a major shareholder since the beginning of commercial operations. However, the second generation of the Murchison family was not as passionate about the oil business as the patriarch had been.
Clint Murchison Jr. was more interested in his ownership of the Dallas Cowboys than he was in Delhi. So when the Cowboys needed a new quarterback in 1980, Delhi and its 17.2% stake in the Cooper Basin gas elds and 31.5% interest in the liquids project were sold to CSR for $514 million. This put a valuation on the entire Cooper Basin resource at that time of about $3 billion.
“Who would ever have believed a Dallas quarterback could cause such turmoil for an Australian gas producer?” The Australian newspaper mused at the time.
When Delhi came up for sale again in 2006, Santos assumed that it was Delhi’s natural heir and announced an agreement to buy its longstanding partner. But fellow Adelaide resources company Beach Energy also wanted Delhi and engineered a secret deal to scoop Santos.
Beach had been operating its own permits in the basin since 1978, substantially increasing its holdings when portions of Santos’ exploration acreage were forcibly relinquished in 1999. The South Australia government concurred with other petroleum exploration companies that Santos was unable to adequately explore the huge amount of acreage it held and wanted to stimulate competition in the basin. Beach’s then-managing director, Reg Nelson, was one who didn’t subscribe to the idea that the Cooper Basin was in decline.
“We seized the opportunity of the burning and long-held belief I had that the Cooper Basin was a long way from being clapped out,” he reflected recently.
The new acreage Beach Energy obtained was located on the anks of the basin. Beach considered these areas more likely to be oil-prone, with oil from the Permian source rocks migrating to Jurassic reservoirs on the fringes of the basin. Discovery of the Kenmore and Bodalla oil elds in southwest Queensland soon proved the gamble correct.
With the surprise purchase of Delhi in 2006, Beach’s ownership of the Cooper Basin increased to encompass a 20.21% interest in the South Australian portion of the Cooper Basin JV (SACB JV) and 23.2% of the southwest Queensland portion (SWQ JV), both operated by Santos. For Beach, the Cooper Basin is now the engine room of the company, responsible for 99% of production and consuming 85% of capex. Santos and Origin Energy hold 66.6% and 13.19% of the SACB JV, respectively, and 60.06% and 16.74% of the SWQ JV.
Santos’ super Cooper success
By Dale Granger, Oil and Gas Investor Australia
Santos’ remarkable recent exploration results in the Cooper Basin have yielded a 75% success rate vs. a 10-year record of 55% success across the broader Santos exploration drilling program.
Bill Ovenden, Santos’ general manager of exploration and subsurface, said the company’s longevity in the Cooper region was a signicant factor contributing to the high rate of discovery of commercial hydrocarbons.
He said the driving force across the Santos exploration portfolio, including the key to favorable Cooper Basin outcomes, was a deep understanding of the rocks in key areas of operation underpinned by regional studies and a play-based approach to exploring.
He said big high-quality seismic datasets were the key to good regional play understanding. An additional overlay of advanced data inversion technologies, prompting new thinking and ideas, is fundamental to the future Cooper exploration harvest.
A balanced portfolio of drilling opportunities added further impetus to yields.
“Typically, our broader exploration program combines a minor measure of higher risk frontier investigation offset against a lower risk program in emerging basins with proven petroleum systems and infrastructure-led or near-eld exploration in mature operations areas such as the Cooper,” Ovenden said.
In the current oil price environment, the investment balance is being directed much more toward the lower risk infrastructure-led inventory.
“The Cooper near-eld exploration contributes strongly to the higher exploration success rates. However, though the basin is quite mature, we are still chasing new play concepts,” Ovenden continued.
“One of the recent breakthroughs has been in a real wildcat play, the deep coal. We are constantly learning new things about the Cooper, pursuing excellence and acquiring technical rationale through the drillbit.”
In 2018, oil production in Argentina reached nearly 500,000 barrels per day (bbl/d), up 2% from 2017 and halting a multiyear decline.
The Dallas-based oil and gas company is bullish on conventional production and believes that is what is needed to develop significant resources internationally.
The Anadarko Basin’s Simpson shale formation is being called “one of the biggest yet-to-be-developed shale plays in the United States.”