Alto currently has up to three rigs exploring its blocks, and all wells drilled have had gas flows.
The company recently merged with another Australian junior, Lach Drummond Resources, and now aims to become a large player in US shale gas. Alto has also opened an office in Charleston, West Virginia, US-based director Jim Trimble told EnergyReview.net.
“We aim to have hundreds of wells through organic growth and acquisitions and could eventually look at a TSX or AIM listing,” he said.
“Unconventional gas – shale gas, coalbed methane and tight gas – is growing rapidly and now comprises about 40% of the US gas supply, up from only 30% in 2003. Very soon over 50% of new fields will be unconventional gas.”
Alto’s five projects include Home Run and Little Sandy/Pigeon Roost in Kentucky, Paint Mountain and Bug Run/Cornstalk/Green Park in West Virginia, and Rich Mountain in Tennessee. Interests in projects vary between 29% at Bug Run/Cornstalk/Green Park and 90% at Paint Mountain.
Wells have already been drilled at Home Run, Little Sandy/Pigeon Roost and Bug Run/Cornstalk/Green Park. Each well has found gas and Alto is now a producer.
The company pulled out of another project, Koppers North in Tennessee, after production rates proved disappointing.
Alto will be doing more drilling this year but it expects its exploration and development campaign to really take off next year, managing director Greg Channon said.
In the booming petroleum sector, the availability of rigs and personnel is a major constraint, and Alto is considering offering drilling companies equity to entice them into long-term partnerships.
While opportunities in this sector are growing, it takes technical knowledge to get the best from a shale gas field, Trimble said. Even the well-established Barnett Shale fields in Texas had only recently seen the application of optimal methods.
Trimble said special formation evaluation and reservoir engineering methods and completion techniques were needed.
“It took 20 years for producers to figure out the best way to frac the Barnett Shale,” Trimble said.
“Even today, it probably takes a year for operators to develop optimal completion models for new fields. Massive hydraulic fracturing treatments and horizontal and multi-branched well bores are needed. No one model will work best everywhere. A lot of finetuning is needed.”
Even once a relatively large number of wells are in place, and optimal well completion and fracture stimulation methods are used, production is modest, according to Channon.
“Flow rates from a single shale gas well are nothing to get excited about,” he said.
“They are usually well under 100,000 cubic feet per day. You need to have a large acreage position.
“But the advantage is that they are shallow and only cost a bit over $100,000 to drill. They are also very low risk once you have delineated the field.”
Because of this, it is relatively easy to get capital for exploration, according to Channon.
“I’m constantly fielding calls offering us finance,” he said. “You don’t have to go back to the markets every time you want to do something.”
