Beach Energy’s first foray into unconventional gas was in the CSG business in conjunction with Arrow Energy, where the companies developed a project for a local power station.
Early in the project development, Beach identified issues in terms of land ownership and water disposal associated with CSG operations and decided to explore other options. Mr Nelson says “At the time I was aware of what was developing in the United
States (US) in terms of shale gas, and the fact that shale gas had overtaken CSG in terms of production.”
The company then moved out of the burgeoning CSG industry and into the relative unknowns of the shale gas industry, which had at that point failed to receive recognition in terms of investment and production development within Australia.
Beach began looking within its permits for ideal shale development opportunities, and originally considered drilling in the Otway Basin where the company had witnessed gas flowing from shale fractures during drilling operations. However, it was decided that the Otway site had greater potential for conventional oil and gas, and Beach cast its net wider, looking at prospective basins around Australia. The company found the best acreage in the Cooper Basin. “We saw that in terms of gas potential the Nappameri Trough in the Cooper
Basin was probably superior in terms of shale gas production due to the thickness of the shales and the overpressured reservoirs,” says Mr Nelson.
“We saw very strong similarities to Haynesville Shale in the US, and so that was our initial drive.” Beach then moved quickly toward an aggressive and dominant tenement position within the Cooper Basin, sighting the Nappameri Trough as the key objective with a focus on the principal permits of PEL 218 in SA and ATP 588 in Queensland. This allowed Beach to add to its portfolio of tenements, which already included interests in the Santos/ Origin Energy joint venture.
“We have a very strong net acreage position in the Cooper Basin, I would say in excess of a million acres if you want to talk in US terms,” says Mr Nelson.
Having secured the ideal tenements according to seismic research, the company set out on a thorough and considered test drilling campaign.
Mr Nelson says “The next process was to start drilling some wells to test the thickness of the shales, the thermal maturity or the degree of over pressuring, the organic content of the shales, and particularly the mechanical properties – that is how amenable the target zones would be to fracturing.” The first test was the Encounter-1 well, which spud in late 2010, followed closely by the Holdfast-1 well. “These were quite important wells because we deliberately drilled them in the deepest parts of the trough away from any structures.
Structures can be faults or seal rocks that have the potential to trap gas, so if you are able to prove that gas exists outside of these structural closures, you have a strong chance of gas occurring right across the basin,” Mr Nelson says.
Beach gambled what was an expensive drilling program on this premise, hoping for a reasonable shale thickness in the Roseneath-Epsilon-Murteree (REM) sequence and a decent flow rate of gas. However, the company’s discovery changed the outlook for the development of this unconventional opportunity entirely.
“We proved that not just the shales of the REM sequences were gas-saturated, over-pressured and thicker than we first thought, but we also found that the sandstones and other lithologies located above and below our target shales were gas-saturated. So, on top of what we thought was a highly prospective shale gas play, we believe we have what is effectively known as a basin-centred gas play. This means that the shales are probably still generating gas, and there is a very thick section of normal tight gas potential.”
This encouraging discovery was delivered off the back of Beach undertaking an extensive core analysis of the wells. “We drilled these two wells and took extensive core, which is very expensive. It was a very bold play to drill
off-structure in the centre of the basin and take the amount of core that we did, but it was well worth the cost.”
Beach then embarked on the second phase of its drilling program and began fracture stimulation, starting with the Holdfast-1 well.
Mr Nelson says “The whole fracture stimulation process was experimental as we wanted to understand the best way to stimulate the target zones, how to measure the fractures, what sort of orientation they would take, and what size of proppant would work most effectively.”
Proppant refers to sand particles used to ‘prop’ the factures open so that gas can flow after the fracture stimulation process.
“We tested seven zones and experimented with each zone in terms of fluid viscosity, perforation techniques and proppant size. We were able to learn a lot about the stimulation process and which
zones were more amenable to it.”
Initial flow rates were then calculated and the results “were beyond anyone’s wildest dreams” according to Mr Nelson.
“We would have been very happy with some flow of gas to surface, even a few hundred thousand cubic feet per day would have been an excellent result, but we ended up with 2 million cubic feet (MMcf) in the initial flow, which was well beyond expectations! To get that sort of flow rate from seven pinpoint fracs from a vertical well was outstanding in every possible way.”
Following such careful and extensive testing, Mr Nelson reflects on the moment when the well began to flow. “There was a lot of champagne! It was really one of those wonderful moments.” Beach’s next move was to book a contingent resource for each well, based
on a 100 square km grid. “We knew from seismic data that the shales are continuous, which gave us the confidence to book a 2C contingent resource of 1 trillion cubic feet (Tcf) of gas per well.
So we now have a contingent resource booking of 2 Tcf of recoverable sales gas.“PEL 218 is 1,600 square km, so by extrapolation there is certainly potential for at least 15–20 Tcf of gas in terms of 2C resources. We intend to assess that potential by drilling at least five vertical exploration wells in 2012 in selected areas around the permit,” says Mr Nelson.
Looking forward
Beach has contracted a new-build rig that is based on rigs that are used to drill horizontal wells into the Haynesville Shale in the US. This rig is due to arrive in April 2012. Similar rigs in the US are able todrill to a depth of 3,000 m, and horizontally to a distance of 1,500 m.“Typically, to get production level flow rates from these shales, you want to maximise the exposure of the well bore to the shales. The Cooper Basin shales and sands in the heart of the Nappameri Trough present a target zone of up to and
possibly in excess of 1 km thick”, says Mr Nelson.
“We are importing this rig, which is on a two-year extendable contract, and we plan to drill three horizontal pilot production wells, on top of the five planned vertical exploration wells. We will then undertake multi-stage fracture stimulation in each of these wells, which we expect to generate much higher flow rates than that delivered from our Holdfast-1 well.”
In comparison, Haynesville horizontal shale wells can generate initial flow rates of up to 20 MMcf/d, which Beach is hoping to replicate. “We hope that the five-well vertical exploration program for 2012 will build our resource base considerably. 2 Tcf is a great
start, so if we achieve 1 Tcf per vertical exploration well, this could increase our unconventional resource by a further 5 Tcf, and confirm the concept of the basincentred gas play. It is worth noting that the basin-centred gas play has the potential to
double the resource per well.”
Beach has also strategically chosen to explore shale in the Cooper Basin due to its close proximity to existing pipeline and processing infrastructure. Beach has a 20 per cent interest in a nearby sales gas pipeline and the Moomba processing facility. Mr Nelson concedes that “the ability to get anything to market is critical”.
The future of shale in Australia
Beach’s view of Australia’s future in shale is bright. Mr Nelson says “This is a new shift in the global energy scene in terms of oil and gas. Shale gas has had a profound impact on the US and is starting to impact on other countries. The
International Energy Agency has identified Australia in particular as the fourth largest in terms of shale potential.”
Companies developing shale in Australia have the benefit of looking to the US for direction. Mr Nelson says “The US was short on gas until about five years ago, then the shale gas revolution came along in such volumes that the US is now looking
to export that gas, rather than import it.”
Mr Nelson points out that unfortunately for the US the development of its shale reserves coincided with the global financial crisis, which saw a drop in gas demand and subsequent decrease in gas prices.
Australia has remained relatively financially stable to this point, and the development of the local shale industry is taking place during a more financially prosperous time. Mr Nelson points out that analysts’ predictions for Australia’s gas prices are trending upward.
“The Australian situation, particularly on the eastern seaboard, is interesting in the sense that at least 80 per cent of the CSG reserves are in the control of the large companies looking to convert it to LNG for export. Most commentators see the gas prices locally going from $A4 to $A7 or $A9 a gigajoule in the next few years, so there’s certainly going to be demand.
“What it will really boil down to is the ability for people to have a choice as to where the gas is coming from, and more particularly what price they can get the gas. If you are able to produce shale gas at a price that is competitive with CSG, or perhaps even better, it will offer the end-user a more competitive choice,” says Mr Nelson.
Cost comparisons:CSG versus shale
Mr Nelson says that the cost structures between CSG and shale gas vary. “The capital cost of drilling in a shale gas well is much greater than a CSG well, but you end up with more recoverable gas per shale gas well. In addition, the operating costs of shale wells are lower, mainly because wells are spaced with less density and there is no need to de-water, as is the case with CSG. Profitability really comes down to the unit cost of developing and operating gas production over the entire
lifetime of the well.”
“We think we understand drilling costs pretty well in the Cooper Basin as we have been there for decades. We believe that fracture stimulation will be available at the right prices. It really then comes back to production rates and how much expected ultimate recovery you get per well. These are things we don’t know yet, but of course that will be the objective of these pilot production wells next year that will give us the answer to this question.”
Success in a shale play comes down to the quality of the acreage held and Beach believes it has secured the sweetest spot in the Cooper Basin. “The best place to be is in the centre of the basin, where the shales are thick and over-pressured. The
economics there are likely to be markedly different from the marginal areas.”
Managing shale’s reputation
Similar to the Australian CSG industry, shale in the US has faced negative public perception and landholder issues. When asked how Beach would minimise issues such as these, Mr Nelson replies with confidence, “We deliberately chose the Nappameri Trough first of all because it’s right in the centre of the Cooper Basin gas operations to begin with. It’s located in semi-desert country, there are few pastoral activities and we have a very good relationship with the station owners. They are familiar with the industry.”
“The difference between shale and CSG is that there is a lot less density per well, and there are no water disposal issues. For us, we’re also not drilling in an area of prime agricultural land. The separation between the shales we are looking at and
the nearest aquifer of any consequence is around 1,000–1,500 m.”
Mr Nelson believes that shale will offer consumers choice as to where their gas is sourced and the methods of extraction used.
Beach’s advice for those looking to drill shale gas
Mr Nelson says that Beach’s entry into the shale gas industry was careful and considered. “Our objective was to learn as quickly as possible, and the most important advice that we received was ‘spend money doing your homework first”.
“It is important not to race in and start drilling and fracture stimulating. We took a bold step in drilling and coring the Encounter and Holdfast wells, but what we learnt from them was of immense value that will hopefully result in expediting our project.”
