Capital efficiencies of Argentina’s tight gas wells are on par with the best plays in US
HOUSTON— Operators in Argentina are focusing on reversing the Neuquén basin’s gas production decline by targeting low-permeability, tight gas reservoirs, says consultancy Wood Mackenzie.
The shift to tight gas production over the last three years is being driven by pricing incentives and lower costs versus shale gas wells. However, at current costs only the best tight gas wells break-even at the incentivized US$7.50/mmbtu gas price according to the latest Wood Mackenzie analysis.
In the past two years, tight gas production has almost tripled in the Neuquén basin.
By Q1 2016, production reached 565 mmcfd, or 16 million cubic meters per day (Mm3/d), representing a quarter of the basin’s output.
“Tight gas continues to provide big opportunities for operators in Argentina,” said Horacio Cuenca, Director of Latin America Upstream Research for Wood Mackenzie.
“However, our recent analysis shows that there is a lot of variability in well performance and economics across all tight gas formations.”
Well performance has been extremely variable across all formations. Of the six tight gas formations studied, the median well in the Neuquén basin has a 90-day initial production rate (IP90) rate of 56 thousand cubic meters per day (km3/d), or 2 mmcfd, with top quartile wells performing about five times higher than the bottom quartile.
Horizontal wells targeting the Mulichinco formation promise the highest Estimated Ultimate Recovery, at more than 5 bcf.
The best wells in Punta Rosada are expected to achieve similar results with a vertical construction. Representative wells in the Lajas formation, however, are expected to recover a third of that volume, according to Wood Mackenzie.
“The large variability indicates that tight gas in Neuquén will continue to require a statistical development approach. This means that large, multi-well development programs will be used to spread the productivity risk among a large number of wells; this approach is more similar to shale than to conventional developments,” added Cuenca.
Higher costs aren’t necessarily bad, as long they improve production
Longer laterals, more fracture stages and increased water and propant usage are all factors that have been shown to enhance production but also markedly increase well cost.
Different sections of the same play also require unique considerations givenvariance in rock quality and thickness, pressure and temperature.
“What is critically important is the relationship between the cost of these wells and the productivity they can achieve,” said Cuenca. “Our analysis shows that the tight gas wells with the highest costs also have the highest EURs and IP rates.”
Using type-well Estimated Ultimate Recoverys and Wood Mackenzie’s current well cost estimates, Mulichinco horizontal wells and Punta Rosada vertical wells (the most expensive in the basin, on average) are profitable at or below the government’s US$7.50/mmbtu incentivised gas price.
These costs reflect a 15 per cent reduction versus 2015 levels, driven by the strong peso devaluation at the beginning of 2016.
However, considerable additional reductions are still needed for type wells in these and other formations to be economic at the US$5.20/mmbtu average gas price without incentives.
“Beyond discovering and focusing on the best producing sweet spots in each formation, enhancing EURs through more expensive wells (i.e. horizontal sections or targeting deep, thick formations with a high number of frac stages) seems a more plausible path for improving tight gas well economics in the short term, rather than the drastic costs reductions needed with current EURs,” said Cuenca.
Capital efficiencies of Argentina’s tight gas wells are on par with the best plays in the US
Capital efficiencies on IP rates in the Neuquén basin ranged between US$9,340 perboe/d and US$20,000 per boe/d. EUR capital efficiencies ranged between US$13.7 per boe and US$29 per boe.
Wood Mackenzie recently estimated capital efficiencies for unconventional wells within the Karnes Trough and Edwards Condensate sub-plays of the Eagle Ford in southern Texas.
The study leveraged Wood Mackenzie’s North American Well Analysis Tool for well costs and productivity, and focused on wells completed by the largest US operators during 2014 and 2015.
Capital efficiencies on IP rates ranged between US$8,000 per boe/d and US$15,000 per boe/d.
EUR capital efficiencies ranged between US$16 per boe and US$31 per boe.