A Technical View on Australian Shales
Central Petroleum Manager of Geology, Greg Ambrose, spoke about unconventional hydrocarbons in the Amadeus and Georgina Basins in Central Australia at the Shale Gas World 2011 conference in Adelaide.
In the first of three brief presentations of a technical showcase, Ambrose said they had turned out to be very promising unconventional hydrocarbon provinces. “Here is the Georgina Basin acreage, which we are particularly interested in,” he said, while looking at a map on the screen behind him.
But first he dealt with the Amadeus Basin unconventional hydrocarbons – Ordovician Larapinta Group. “Many of you have probably heard of the Horn Valley Siltstone,” he said. “It’s a rather remarkable source rock.”
“It doesn’t look that spectacular often in core. It’s not overly thick. It doesn’t have a lot of shale, but we can prove its source of 200 million plus barrels of oil equivalent – that’s recoverable – in the Amadeus Basin and we believe it has vast potential for unconventional.”
A slide was presented to show the three transgressive cycles in the lower Larapinta Group. According to the slide, the three transgressive cycles are capped by marine shales, which become increasingly oxic up through the zone, and the most important source rock is the Horn Valley Siltstone – containing up to 9 per cent organic carbon. “Basically the environment was initially a deep epeiric marine basin which was anoxic at the base of the water column, but included a mid-water oxygen minimum zone above an oxygenated zone.”
Ambrose also showed a slide of shale gas/oil summary parameters, Horn Valley Siltstone. “Now the Horn Valley – it’s a bit deceptive – it’s a deceptive source rock,” he said. “Often the TOCs are only hovering around 1-2 percent, but they do actually rise up to 9 per cent.”
Ambrose showed a slide of the Horn Valley Siltstone Continuous Gas/Oil. “We have mean reserves of 11.3 Tcf,” he said.
Another slide showed a table of the Amadeus Basin Unconventional Probalistic Prospective Recoverable Resources (DSWPET, 2010). Under the assessment unit of ‘Total Gas all gas Aus’ there was mean 26.2 TCFG, and under ‘Horn Valley Continuous Oil AU’ was mean 1.061 Billions of BBLS.
Regarding the Lower Larapinta mean prospective recoverable resource 26 TCFG and 1 B BBLS, Ambrose said the next steps were to examine cores from Surprise-1 side track, “ he said. “We will undertake absorption studies.
“We will be drilling holes outside of closure and in the gas window and hopefully we will get enough encouragement to define a contingent resource. Then we will proceed to drill sweet spots and undertake exploration drilling.”
Ambrose said in the Southern Georgina Basin, the main target was the Middle Cambrian Arthur Creek Formation.
A slide appeared that showed the Cambrian carbonate ramp plays - the inner ramp facies (reservoir), middle ramp facies (source/seal reservoir) and the outer ramp facies (source).
Ambrose also talked about free gas porosity. While referring to a slide, he said the majority of gas resides in the nano-porosity in organic matter. “Sometimes the gas in the intra crystalline porosity and sometimes a percentage of gas is in the inter-particle porosity,” he said.
He showed a photo of what the rocks looked like from the outer ramp. “Good gas shows, good oil shows throughout the whole basin. It’s a delightful source rock”
Ambrose finished his presentation with the words, “We have only scratched the surface in Central Australia.”
RISC Geoscience Manager, Joe Salomon, stepped up on the stage to present some views on Australian shale gas.
Salomon said RISC was a consultancy that provided independent advice to the oil and gas industry in both conventional and unconventional projects. “We work globally,” he said. “We have offices in Perth, London and Brisbane.”
While showing a map of Australia, Salomon said the industry in Australia was really in its infancy. “There is barely any information at all about gas contents of specific shales and that’s obviously a key component of what we need to know,” he said.
“There are many basins. There are many shale sections. Very few have been tested with purpose designed shale gas flow tests.
“But despite that, it’s tipped by many analysts that Australia will be the next major development in the world in shale gas.”
Salomon also pointed out a couple of critical issues. “The availability of crews and the capacity of just the basic supply of services that are needed to develop it,” he said. “The other thing is the cost of supply.”
In a quick overview, he said the Cooper Basin was the most advanced. “Wells have been drilled in the Perth Basin,” he said.
“There are deals that have happened in the Canning Basin and the Beetaloo Basin. Nobody had heard about the Beetaloo Basin until really quite recently.”
Salomon also mentioned there had been drilling in the Southern Georgina, potential had been identified in the Otway Basin, the Bowen and Maryborough Basins are targeted, and there was an enormous land grab in the Northern Territory.
Salomon presented a detailed overview of the various basins. Some of the most interesting included the Cooper Basin. “There are a number of troughs, but the focus at the moment is on the Nappamerri Trough,” he said.
“That is primarily because of the thicknesses of the REM sequence. In the Nappamerri Trough it’s much thicker. Again, we are going to see as time develops where the sweet spots are.”
In the Perth Basin, Salomon said the main focus was the Dandaragan Trough. “There are two main targets,” he said. “The Carynginia Shale and Triassic Kockatea Shale.”
He said there was also tight gas potential in adjoining formations.
According to Salomon, one of the main points about the Canning Basin was that it was underexplored. He said in the Kidson Trough there was a very rich source rock called the Goldwyer and it looked very attractive for shale gas potential. “In the Fitzroy and the Gregory Troughs there are a number of rocks being targeted, including the Laurel mostly, and the Anderson formations, the Gogo and the Goldwyer formations” he said. He added there were other formations that may have potential in the Canning Basin.
Salomon showed a slide of the Beetaloo Basin in the Northern Territory and said there were two shale zones – called Kyalla and Velkerri shales. “Extremely rich source rocks,” he said.
Regarding the Bowen Basin in Queensland, he said that it was coal seam territory, but some companies were now looking at shale gas potential, and he described the Southern Georgina Basin as an emerging new play in highly organic rich Cambrian Arthur Creek marine shales.
Completing the technical showcase was Dr Dennis Cooke, Program Manager, Unconventional Resources at the Australian School of Petroleum, University of Adelaide.
Dr Cooke gave a brief presentation and said the main point of his message was that there was a lot more production variation in unconventional reservoirs than conventional reservoirs.
“One way to look at this is to consider the production rate of different wells,” he said.
Dr Cooke showed a slide of unconventional plays and said there were a lot of mediocre wells, and a few great wells at the high end that seemed to pay for everything else.
He also referred to a cumulative distribution curve of some reservoir data and said the top one third of the well was producing about 60 per cent of the gas. “Performance like this appears in shale gas and coal seam gas,” he said.
Dr Cooke brought up production variability in Barnett Shale. “The big takeaway is that there can be a 10 fold variation in productivity between the worst wells and the best wells,” he said.
He said there were a couple of important points here. “Once you are in development in one of these plays, it’s high risk,” he said. “You can drill two wells next to each other, say this well and this well, and have a 10 fold variation in production rate and payback period.”
Dr Cooke said the other important point was to consider the impact of this variability on new ventures mode pilot programs. He raised the question of what caused production variations in a shale gas play and said nobody knew for certain yet. “There is no universal silver bullet,” he said.
“People are figuring this out for one play, but what they learn generally can’t be applied to all plays. It turns out that all shales are different. I don’t know how many times I’ve heard that, but I think that’s one of the keys.”
Dr Cooke had a look at some proposed solutions to help in the understanding of production variability. He mentioned the concepts of petroleum systems analysis.
In conclusion, Dr Cooke reiterated that shale gas production rates were highly variable and there were many possible explanations for this variation and solutions. “But what you learn from one shale probably won’t apply to all,” he said. “That’s because all shales are different.
“For me, using the concepts of petroleum systems analysis and recognizing that your scale will be much smaller, is a good way to get a handle on what’s going on with your shale,” he said.