Just ask Nexus Energy about how it was able to prove two multi-billion dollar oil companies wrong about the Longtom gas field.

The find was considered sub-commercial when first discovered by BHP Billiton in 1995.

But as southeast Australia’s gas markets started growing, Nexus was encouraged to take a second look at the discovery, 14km southwest of the small Santos-owned Patricia-Baleen gas field.

Nexus acquired the Vic-P54 permit containing Longtom and in 2004 took on United States major Apache Energy as a farm-in partner and operator.

But the partners could not see eye-to-eye on results from the Longtom-2 well where a drill stem test failed to flow hydrocarbons to surface, seemingly suggesting reservoir damage.

This was enough to make Apache back out of the development. But not Nexus, which was a minnow with a lot riding on the success of this field.

After looking back over the data, it concluded the DST had not been done properly because the test tool had failed.

And so an ambitious plan arose to drill and complete an extended-reach appraisal well, to assess the productivity of an undeveloped play known as the Emperor Subgroup.

Nexus’ exploration manager Philip Smith said the company came up with an innovative new way of using the seismic data that would play a key role in drilling Longtom-3 and the subsequent conclusion that the field was suitable for development.

“The main issue with Longtom had always been the seismic – just being able to predict where the reservoir was,” Smith said.

“Seismic is generally used to define the shape of a structure. But we wanted to use it to see what was going on inside the structure.”

This required Nexus to continuously compare the seismic imaging to real-time data received as the Longtom-3 well was drilling ahead.

“The initial task was to locate the best gas sand targets, and this was primarily addressed by analysis of elastic rock properties, which led to a seismic inversion processing technique able to differentiate between thicker gas and water-filled sands,” Smith said.

“Mapping out the anomalies indicated by this technique provided a critically important guide for designing the optimal well path.”

The experiment paid off. On production testing last September, the well flowed 30 million cubic feet of gas per day from sands that did not test in the Longtom-2 well.

Of even more interest to Nexus, was a second test of a slightly deeper Admiral Formation sands, which achieved flow rates of about 77 MMcfd.

As a result, Smith said Nexus would plan and drill its next appraisal well, Longtom-4, in the same way.

“It was so effective that we want to use exactly the same technique to target upcoming wells in the field,” he said.

The Longtom-3 result had also confirmed the productivity of a new play type, a result that has prompted Bass Strait Oil & Gas to re-evaluate the Judith discovery in a nearby permit.

“Technical work shows that Judith exhibits similar structural characteristics to Longtom,” BSOC managing director Andrew Adams told an investment conference earlier this year.

“And the reservoir quality suggests that if we want to commercialise this prospect, we would need to undertake long lateral completions, like what happened at Longtom.”

Due to come online later in 2008, the Longtom development will see Nexus become the third Bass Strait producer in 40 years after ExxonMobil-BHP and Anzon Australia-Beach Petroleum.

And new explorers to the region are aiming to have their own successes.

Stuart Petroleum has become the latest junior to break out of its Cooper Basin comfort zone and wade into the Bass Strait, behind others like Great Artesian Oil & Gas and Eagle Bay Resources.

There are no half measures in Stuart’s approach.

The company is taking over as operator of the Bazzard prospect in Vic-P53 and if the exploration well is successful, will take a 50% stake in the relevant discovery area.

It may also later decide to extend this arrangement to cover the Vic-P53 permit as a whole.

Altogether a bold move, considering this is Stuart’s first offshore venture and first move outside South Australia.

Stuart’s managing director Tino Guglielmo said Vic-P53 has been a difficult nut to crack.

The permit is “right in the guts” of the Gippsland Basin, in an area that has been difficult to map due to the degree of seismic complexity resulting from overlying high-velocity canyon fill transecting the region.

But the junior is confident newly reprocessed 3D seismic data could solve this problem.

Guglielmo said the Bazzard structure showed a seismic amplitude anomaly broadly coincident with the area of structural closure of a highly permeable Intra Latrobe sand horizon.

“This sands has been recognised from previous drilling in the basin,” he said.

“The amplitude anomaly is considered likely to be mapping contrasts in seismic impedance, characteristic of hydrocarbons.”

The sand is sealed by overlaying shales and is believed to be well located to trap oil and gas generated in the thick sediments underlying this sector of the Gippsland Basin.

Guglielmo said the company had spent the past six months getting its head around the block in an attempt to understand why the eight or nine wells drilled in the block to date had failed.

“Earlier wells in the permit were drilled without the benefit of 3D seismic and mainly targeting the Top Latrobe. Many of the wells were not even drilled to the Intra Latrobe and none of those wells are now believed to have been optimally located.”

“The earlier 2D seismic data sets did not allow the use of modern depth conversion techniques so the target horizons simply couldn’t be imaged properly.”

Stuart isn’t the only one to encounter seismic imaging problems.

Even Kingfisher – the basin’s biggest field in the 1960s – was nearly missed because of seismic interpretation difficulties.

Forty years on, headaches are still being caused by the velocity interpretation stage of the seismic data analysis.

During development drilling of the Basker-Manta-Gummy project – a relatively well understood discovery – operator Anzon Australia was surprised to learn the fields had moved to the southeast of their interpreted positions.

“We were very fortunate because [the discovery] was bigger than we thought it was,” Anzon’s Steven Koroknay said.

“But it shows that even at this late stage, we’re still having surprises regarding the outcome of drilling at fields already known to be there.”

Anzon and Nexus may have been the Gippsland Basin’s most recent two success stories, but the region has claimed many more casualties.

Despite Stuart’s optimism, recent exploration efforts in the region have largely proved fruitless.

Moby Oil & Gas claims it can’t justify commercialising its 60 billion cubic feet Moby gas discovery at current gas prices and drilling costs.

Then there is BSOC, which drilled four consecutive dry wells last year – a disheartening result considering the company was set up specially to get in on the ground floor of the Bass Strait’s exploration revival.

Even Nexus’ own exploration program has resulted in a series of dusters at Fur Seal, Culverin-Scimitar and Galloway.

Koroknay, who became well acquainted with the region during his time as Esso area manager, cautions that exploring Gippsland will probably continue to be unpredictable.

First published in the September issue of Petroleum magazine